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Research Papers: Petroleum Engineering

Experimental and Theoretical Quantification of Nonequilibrium Phase Behavior and Physical Properties of Foamy Oil Under Reservoir Conditions

[+] Author and Article Information
Yu Shi

Petroleum Systems Engineering,
Faculty of Engineering and Applied Science,
University of Regina,
Regina, SK S4S 0A2, Canada
e-mail: shiyu202@uregina.ca

Daoyong Yang

Petroleum Systems Engineering,
Faculty of Engineering and Applied Science,
University of Regina,
Regina, SK S4S 0A2, Canada
e-mail: tony.yang@uregina.ca

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received March 2, 2017; final manuscript received May 3, 2017; published online July 17, 2017. Editor: Hameed Metghalchi.

J. Energy Resour. Technol 139(6), 062902 (Jul 17, 2017) (11 pages) Paper No: JERT-17-1106; doi: 10.1115/1.4036960 History: Received March 02, 2017; Revised May 03, 2017

A novel and pragmatic technique has been proposed to quantify the nonequilibrium phase behavior together with physical properties of foamy oil under reservoir conditions. Experimentally, constant-composition expansion (CCE) experiments at various constant pressure decline rates are conducted to examine the nonequilibrium phase behavior of solvent–CO2–heavy oil systems. Theoretically, the amount of evolved gas is first formulated as a function of time, and then incorporated into the real gas equation to quantify the nonequilibrium phase behavior of the aforementioned systems. Meanwhile, theoretical models have been developed to determine the time-dependent compressibility and density of foamy oil. Good agreements between the calculated volume–pressure profiles and experimentally measured ones have been achieved, while both amounts of evolved gas and entrained gas as well as compressibility and density of foamy oil were determined. The time-dependent effects of entrained gas on physical properties of oleic phase were quantitatively analyzed and evaluated. A larger pressure decline rate and a lower temperature are found to result in a lower pseudo-bubblepoint pressure and a higher expansion rate of the evolved gas volume in the solvent–CO2–heavy oil systems. Apparent critical supersaturation pressure increases with either an increase in pressure decline rate or a decrease in system temperature. Physical properties of the oleic phase under nonequilibrium conditions follow the same trends as those of conventionally undersaturated oil under equilibrium conditions when pressure is higher than the pseudo-bubblepoint pressure. However, there is an abrupt increase of compressibility and decrease of density associated with pseudo-bubblepoint pressure instead of bubblepoint pressure due to the initialization of gas bubble growth. The amount of dispersed gas in the oleic phase is found to impose a dominant impact on physical properties of the foamy oil. Compared with CCE experiment at constant volume expansion rate, a rebound pressure and its corresponding effects on physical properties cannot be observed in the CCE experiments at constant pressure decline rate.

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Figures

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Fig. 1

The schematic diagram of PVT experimental setup

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Fig. 2

Flowchart for matching volume–pressure profile with the proposed newly numerical method

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Fig. 3

Pressure as a function of expansion volume for (a) CO2–heavy oil systems, (b) CH4–C3H8–heavy oil systems, and (c) CH4–CO2–heavy oil systems under equilibrium and nonequilibrium conditions

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Fig. 4

Amounts of evolved gas and entrained gas in (a) CO2–heavy oil systems, (b) CH4–C3H8–heavy oil systems with pressure decline rate of 20 kPa/min, and (c) CH4–CO2–heavy oil systems with pressure decline rate 20 kPa/min at 342.7 K

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Fig. 5

Compressibilities and densities of oleic phase in (a) CO2–heavy oil systems, (b) CH4–C3H8–heavy oil systems with pressure decline rate of 20 kPa/min, and (c) CH4–CO2–heavy oil systems with pressure decline rate of 20 kPa/min at 342.7 K

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Fig. 6

Pressure as a function of expansion volume for CO2–heavy oil systems at 323.4 K

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