Page 273 - Reservoir Formation Damage

Two-Phase Formation Damage by Fines Migration 253

0.1

I" 0.01
5
2

0.001
0.5 1 1.5 2 2.5
Pore Volume of Injected Fluid

" Exp.withROS a Exp.w/oROS Simulation
Figure 11-2. Instantaneous to initial permeability ratio (or permeability
alteration factor) vs. pore volume during formation fines migration in single-
phase flow (Liu and Civan, ©1996 SPE; reprinted by permission of the Society
of Petroleum Engineers).

NaCl brine. Berea sandstones generally do not suffer from permeability
reduction during a brine flood. Neglecting the effects of capillary pressure,
the model was used to simulate the two-phase flow test. Relative perme-
ability data were obtained by matching the simulated results with the
measured pressure drop across the core as shown in Figure 11-3. An oil
flood was then carried out to reestablish the connate water saturation. The
core was finally displaced with fresh water and formation damage took
place due to fines migration in two-phase flow. Using the relative perme-
abilities obtained from the two-phase flow test without formation damage,
simulation was carried out to match measured pressure drop as shown
in Figure 11-4. Alteration in the rock permeability, predicted in Figure
11-5, indicates that formation damage due to fines migration in two-phase
flow of oil and fresh water is similar to that of single-phase flow of fresh
water in the presence of residual oil. Detailed information on core data and
model parameters in this case is presented elsewhere (Liu and Civan, 1995).

Damage by Particle Invasion

Experimental data of two similar core samples conducted by Eleri and
Ursin (1992) were used to analyze formation damage due to particle
invasion. The two samples were labeled as Core #26 and Core #27 in
the Eleri and Ursin (1992) study. Prior to flow tests, the core samples