Damage by Formation Fines Migration
Sarkar and Sharma (1990) examined fines migration in two Berea core samples, one of them containing residual oil (ROS). Data for the two core tests are given in Table 11-1. The core samples were first saturated with 3% NaCl brine. Formation damage due to fines migration took place upon fresh water injection. Values of some model parameters were gathered from Khilar and Fogler (1983) while the others were obtained by matching the model responses to the measured data, as summarized in Table 11-2.
The simulation study also confirms that formation damage in the presence of oil is less pronounced. As can be seen in Table 11-2, the amount of formation fines that can be released from the pore surface, αfp°, is 20% less and the rate constant for fines release due to colloidal effects, kcr, fp,w, is 35% lower in the presence of residual oil. Sarkar (1988) conducted a laboratory test using a Berea core of 8.27 cm in length to investigate fines migration in two-phase flow. The core porosity and permeability initially were 0.21 fraction and 0.122 Darcy, respectively. The core saturated with crude oil was displaced with 3%
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.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 permeabilities obtained from the two-phase flow test without formation damage, simulation was carried out to match measured pressure drop as shown in this article. Alteration in the rock permeability, 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
were treated to eliminate formation fines migration. Latex particles of less than 3 microns in size suspended in water were injected into Core #26
at the concentration of 0.5 x 10-4 gm/cm3 and into Core #27 at the concentration of 2.0 x 10-4 gm/cm3. Simulations were performed to examine
the two tests. Permeability alteration versus cumulative volume of injected fluid is illustrated in Figure 11-6 including a comparison between experimental and simulated results. Detailed information on core data and model parameters in this case is presented by Liu and Civan (1993). All model parameters for the two core tests are the same except thatfmin = 0.58 for Core #26 and f„,,-„ = 0.41 for Core #27. The difference reveals that higher particle concentration causes more pores being plugged. Both experimental and simulation results indicate that particle concentration is a major factor for formation damage caused by particle invasion.
Damage by Mud Filtration
Rahman and Marx (1991) studied formation damage by mud filtration. A core sample was contaminated by circulating a drilling fluid over the surface of core inlet under a constant differential pressure of 34.54 atm across the core. Before mud filtration, the core was saturated with 1.5% KC1 water to prevent formation fines migration. Permeability
alteration along the core was measured after one hour of mud contamination. Data for the core test and values of model parameters for simulation are presented elsewhere by Liu and Civan (1993). Experimental and simulated results for drilling fluid loss versus time and permeability alteration versus core distance after one hour of mud contamination are illustrated in this article. Simulation results indicate that the model can favorably represent the process of mud filtration. Another laboratory test involving dynamic mud filtration was conducted by Jiao and Sharma (1992).
A fresh water-based mud was circulated over the surface of core inlet and infiltrated into a Berea core under an average differential pressure of 6.29 atm across the system. This Berea core sample was previously saturated with 3% NaCl brine. Formation damage in this test is caused by external solid invasion and formation fines migration. Pressure taps were placed at different locations along the core of 20.34 cm in length to measure permeability change during the test. Experimental results of permeability alteration in the core section between 6.35 cm and 11.43 cm from core inlet compare quite well with simulation results. Further discussion on the simulation of this test is presented elsewhere (Liu and Civan, 1993).
Prediction of formation damage due to dynamic mud filtration in twophase flow was also carried out to demonstrate the capacity and application
of the model and to provide a comparison with single-phase flow results. If the core studied by Jiao and Sharma (1992) was saturated by oil prior to mud filtration, the invasion of the water-based mud would lead to two-phase flow of oil and water in the rock. The same model parameters determined above for mud filtration in single-phase flow were used. Additional data necessary for simulation, including connate water saturation, residual oil saturation and relative permeabilities, are adapted from the case of fines migration in two-phase flow that was also simulated above.
These results indicate that filtration volume and formation damage are significantly less when a water-based mud invades an oil-bearing formation. This is because the total mobility for simultaneous two-phase flow of water and oil is usually less than that of single phase of water in formations, especially in Berea sandstones, which are generally strongly water-wet and have a very low permeability for water phase with the presence of oil in the formations.
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