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Influence of Large Drawdowns in Oil Reservoirs on Fluid Temperature and Fluid Properties

[+] Author Affiliations
R. Islam, A. R. Hasan

Texas A&M University, College Station, TX

C. Shah Kabir

C. S. Kabir Consulting, Houston, TX

Paper No. OMAE2017-62538, pp. V008T11A056; 9 pages
doi:10.1115/OMAE2017-62538
From:
  • ASME 2017 36th International Conference on Ocean, Offshore and Arctic Engineering
  • Volume 8: Polar and Arctic Sciences and Technology; Petroleum Technology
  • Trondheim, Norway, June 25–30, 2017
  • Conference Sponsors: Ocean, Offshore and Arctic Engineering Division
  • ISBN: 978-0-7918-5776-2
  • Copyright © 2017 by ASME

abstract

The usual assumption of isothermal flow may be unsuitable in low-conductivity formations where large drawdowns occur. The increase in oil temperature associated with Joule-Thompson (J-T) heating triggers the consequent changes in oil viscosity and density. This paper presents an analytical 1D radial-flow model for estimating the transient flowing-fluid temperature in a single-phase oil reservoir. The model allows oil density, viscosity, and the J-T coefficient to vary with pressure and temperature. A rigorous thermodynamic expression based on fluid PVT behavior underpins the proposed model.

A detailed sensitivity analysis has shown the effect of oil production rate on reservoir heating and consequent changes in fluid properties. Specifically, we observed that fluid temperature increase above the original formation temperature occurs with a decrease in formation permeability, an increase in oil viscosity, and a decrease in overall heat-transfer coefficient. Of course, J-T heating increases with increasing flow rate.

Changes in reservoir temperature occur within about 100 ft. from the wellbore. Overall, the lessons learned from this study illuminates the need for reevaluating tubular design, flow-assurance issues related to dissolved solids, and assessment of well productivity index arising from J-T heating.

Copyright © 2017 by ASME

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