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Research Papers: Petroleum Engineering

A Compositional Thermal Multiphase Wellbore Model for Use in Non-Isothermal Gas Lifting

[+] Author and Article Information
Mahdi Sadri

Fluid and Complex Systems Research Centre,
Faculty of Engineering, Environment and Computing,
Coventry University,
Coventry CV1 2NL, UK
e-mail: sadrim@uni.coventry.ac.uk

Hojjat Mahdiyar

Department of Petroleum Engineering,
Shiraz University,
Shiraz 7196484334, Iran
e-mail: mahdiyar@shirazu.ac.ir

Ali Mohsenipour

Department of Chemical Engineering,
University of Waterloo,
Waterloo, ON N2L 3G1, Canada
e-mail: aamohsen@uwaterloo.ca

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the Journal of Energy Resources Technology. Manuscript received November 21, 2018; final manuscript received April 25, 2019; published online May 17, 2019. Assoc. Editor: Daoyong (Tony) Yang.

J. Energy Resour. Technol 141(11), 112902 (May 17, 2019) (12 pages) Paper No: JERT-18-1824; doi: 10.1115/1.4043653 History: Received November 21, 2018; Accepted April 28, 2019

In this paper, a new compositional mechanistic wellbore model, including gas lifting parameters, is presented. In the governing equations of this model, new terms for mass transfer between phases and the enthalpy of phase change, which are important in non-isothermal gas lift systems, have been considered. These terms have been ignored in some recent research studies and subsequent results show that by ignoring them, serious errors may arise. In the current research study, using a mechanistic drift-flux approach, the pressure distribution in a wellbore was modeled. To verify the new simulator, the results were compared with those of commercial simulators. They were also verified against the phase behavior analysis of the fluid flowing in the wellbore. In addition, in order to show the novel aspects of the new simulator, the results of the presented simulator were compared with the results of a recently proposed model found in the literature. It was concluded that neglecting phase change effects may cause significant errors in calculating pressure and temperature values along wellbores. This error could be significant, up to 24% depending on conditions when flowing fluid pressure is close to its saturation point or in the case of simulating gas lift operation.

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Figures

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Fig. 1

The grid blocks in the well system

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Fig. 2

The solution procedure

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Fig. 3

The comparison between the calculated pressure profiles of the new simulator and three well-known simulators for a natural production scenario

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Fig. 4

The calculated pressure profiles based on model A (incorporating phase change effects) and model B (excluding phase change effects) for the heavy fluid case

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Fig. 5

The calculated temperature profiles based on model A (incorporating phase change effects) and model B (excluding phase change effects) for the heavy fluid case

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Fig. 6

The calculated pressure profiles based on model A (incorporating phase change effects) and model B (excluding phase change effects) for the light fluid case

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Fig. 7

The calculated temperature profiles based on model A (incorporating phase change effects) and model B (excluding phase change effects) for the light fluid case

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Fig. 8

The calculated gas holdup for the volatile oil and black oil fluids

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Fig. 9

The calculated pressure profiles based on model A (incorporating phase change effects) and model B (excluding phase change effects) for the light fluid case (bottom-hole pressure more than saturation point)

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Fig. 10

The calculated temperature profiles based on model A (incorporating phase change effects) and model B (excluding phase change effects) for the light fluid case (bottom-hole pressure more than saturation point)

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Fig. 11

The calculated pressure profiles based on model A (incorporating phase change effects) for the nitrogen and carbon dioxide injections

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Fig. 12

The calculated pressure profiles based on model B (neglecting phase change effects) for the nitrogen and carbon dioxide injections

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Fig. 13

The phase envelope for the reservoir fluid (the fluid below the injection point)

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Fig. 14

The phase envelope for the mixture of reservoir fluid and injected carbon dioxide (the fluid above the injection point)

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Fig. 15

The phase envelope for the mixture of reservoir fluid and injected nitrogen (the fluid above the injection point)

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Fig. 16

The profiles of the superficial velocity along the well for the injection of carbon dioxide and nitrogen

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