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An improved approach to estimate three-phase relative permeability functions for heavy-oil displacement involving instability and compositional effects

Mahzari, P; Taura, U; Cooke, AJ; Sohrabi, M; (2017) An improved approach to estimate three-phase relative permeability functions for heavy-oil displacement involving instability and compositional effects. Energies , 10 (12) 10.3390/en10122008. Green open access

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Abstract

Simultaneous three-phase flow of gas, oil and water is a common phenomenon in enhanced oil recovery techniques such as water-alternating-gas (WAG) injection. Reliable reservoir simulations are required to predict the performance of these injections before field application. However, heavy oil displacement by gas or water can lead to viscous fingering due to the unfavorable mobility ratio between heavy oil and the displacing fluid. In addition, the injection of partially dissolvable gases such as CO2can result in compositional effects, which can bring about a significant reduction of oil viscosity and hence can cause variations of the mobility ratio. Estimations of three-phase relative permeability under such conditions are extremely complex, and using conventional techniques for the estimation can lead to erroneous results. We used the results of four coreflood experiments, carried out on a core, to estimate two-phase and three-phase relative permeability. A new history matching methodology for laboratory experiments was used that takes into account the instability and the compositional effects in the estimation processes. The results demonstrate that a simultaneous CO2and water injection (CO2-simultaneous water and gas (SWAG)) can be adequately matched using the relative permeabilities of a secondary gas/liquid and a tertiary oil/water. In heavy oil WAG injection, the injected water follows the CO2path due its lower resistance as a result of the CO2dissolution in the oil and the resultant reduction of the oil viscosity. This is contrary to WAG injection in conventional oils, where gas and water open up separate saturations paths. It is also important to include capillary pressure (Pc), even in high permeable porous media, as we observed that the inclusion of capillary pressure dampened the propagation of the viscous fingers and hence helped the front to become stabilized, leading to a more realistic simulated sweep efficiency.

Type: Article
Title: An improved approach to estimate three-phase relative permeability functions for heavy-oil displacement involving instability and compositional effects
Open access status: An open access version is available from UCL Discovery
DOI: 10.3390/en10122008
Publisher version: https://doi.org/10.3390/en10122008
Language: English
Additional information: © 2017 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (http://creativecommons.org/licenses/by/4.0/).
Keywords: heavy oil; CO2 injection; enhanced oil recovery; three phase simulation; viscous fingering; compositional simulation; WAG injection
UCL classification: UCL
UCL > Provost and Vice Provost Offices > UCL BEAMS
UCL > Provost and Vice Provost Offices > UCL BEAMS > Faculty of Maths and Physical Sciences
UCL > Provost and Vice Provost Offices > UCL BEAMS > Faculty of Maths and Physical Sciences > Dept of Earth Sciences
URI: https://discovery.ucl.ac.uk/id/eprint/10053035
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