Simulated Annealing for Relative Permeability and Capillary Pressure From Unsteady-State Non-Darcy Displacement

1993 ◽  
Author(s):  
Sezai Ucan ◽  
Faruk Civan ◽  
R.D. Evans
Keyword(s):  
Simulated Annealing ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Unsteady State

Interpreting Relative Permeability and Wettability From Unsteady-State Displacement Measurements

1981 ◽  
Vol 21 (03) ◽  
pp. 296-308 ◽  
Author(s):  
J.P. Batycky ◽  
F.G. McCaffery ◽  
P.K. Hodgins ◽  
D.B. Fisher
Keyword(s):  
Pressure Gradient ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Capillary Forces ◽  
Unsteady State ◽  
The Core ◽  
Fluid Systems ◽  
System Length ◽  
Capillary Pressure Gradient

Abstract A procedure has been developed and tested for evaluating the capillary pressure and wetting properties of rock/fluid systems from unsteady-state displacement data such as that used for calculating two-phase relative permeability characteristics. Currently, the common practice is to conduct most coreflooding experiments so that the capillary pressure gradient in the direction of flow is small compared with the imposed pressure gradient. The proposed method, on the other hand, is based on performing low rate displacements during which capillary forces and, hence, end effects can influence the saturation distribution and pressure response of the core sample. Besides providing a means for monitoring capillary forces and wettability during the dynamic displacement test, the proposed method has the advantage of permitting the displacement tests to be conducted at rates more typical of those in the reservoir. Thus, it is possible to avoid potential problems such as fines migration and emulsion formation, and the method permits a realistic representation of transient interfacial effects that can be important with reservoir fluid systems and chemical flooding agents. Specifically, the method involves performing low rate displacements between the irreducible-water and residual-oil endpoint saturations. Except for the added provision of stopping, restarting, and sometimes reversing the flow after the endpoints have been reached, these are routine unsteady-state displacements in which the standard pressure drop is measured external to the core between the inlet and outlet fluid streams. The dynamically measured capillary pressure properties—besides indicating strong, weak, intermediate, or mixed wettability—then can be used to derive relative permeabilities from the displacement data. Examples of the technique for determining wettability are given for pure-fluids/Berea-sandstone andreservoir-fluids/preserved-reservoir-rock systems. Introduction It long has been recognized that capillary forces can influence the results of relative permeability and oil recovery measurements on core samples.1–5 A scaling criterion for linear displacement tests has been proposed to remove the dependence of oil recovery on displacement rate and system length.5 The objective is to avoid appreciable influence of capillary forces on the flooding behavior that causes a spreading of the displacement front and the well-known end effect or buildup of the wetting phase at the ends of the core. The suggested scaling causes the capillary pressure gradient in the direction of flow to be small compared with the imposed pressure gradient and is expressed asEquation 1 where L is system length (in centimeters), µ is displacing phase viscosity (in centipoise or millipascal-seconds), and q/A is flow rate per unit cross-sectional area (in centimeters per minute). Bentsen6 refined the criterion for neglecting capillary forces to include consideration of the mobility ratio. In related work, Peters and Flock7 recently proposed a dimensionless number and its critical value for predicting the onset of instabilities resulting from viscous fingering at unfavorable mobility ratios. In apparent contrast to the scaling coefficient suggested in Eq. 1, displacements were shown to decline at high flow rates for a given core system and wettability condition.

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