Factors influencing unsteady relative permeability of a mixed-wet reservoir rock

Journal Article · Sun Sep 01 04:00:00 EDT 1991 · SPE Formation Evaluation (Society of Petroleum Engineers); (United States)

DOI:https://doi.org/10.2118/18292-PA· OSTI ID:5893647

Mohanty, K K; Miller, A E ^[1]

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1. Arco Oil and Gas Co. (US)

Capillarity, viscous fingering, and heterogeneity influence the flow in a core plug and hence affect the relative permeability determined from an unsteady test. Several unsteady water/oil relative permeability tests were carried out in a mixed-wet core while in-situ 3D saturation distribution was monitored by a computerized-tomography (CT) scanner. Results illustrate included in this paper that, in the early part of the Johnson-Bossler-Naumann (JBN) method, relative permeability is dominated by fingering and heterogeneity effects. The later part of this method ({gt}1 PV), however, represents the relative permeability of the end-face saturation and is influenced by the capillary number and throughput. Thus, laboratory results must be scaled to the field on the basis of the flow parameters: end-effect, capillary, instability, and heterogeneity numbers.

• OSTI ID: 5893647
• Journal Information: SPE Formation Evaluation (Society of Petroleum Engineers); (United States), Journal Name: SPE Formation Evaluation (Society of Petroleum Engineers); (United States) Vol. 6:3; ISSN 0885-923X; ISSN SFEVE
• Country of Publication: United States
• Language: English

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CAPILLARY FLOW
COMPUTERIZED TOMOGRAPHY
DIAGNOSTIC TECHNIQUES
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FLOW VISUALIZATION
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RESERVOIR ROCK
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WELLS
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