As explained by Keelan and Koepf (1977) fracturing fluids cause formation damage by water-block, solids invasion associated with fluid leak-off, and clay hydration in the near-fracture formation. Therefore, it is important to use compatible fluids and fluid-loss additives. Hence, they recommend performing tests on core samples extracted from the reservoir formation, in which fractures will be created. In these tests, the spurt loss, fluid-loss coefficient, effect of additives, acid solubility of formation, fines release with the acid reaction, are typically determined (Keelan and Koepf, 1977).

Evaluation of Workover and Injection Fluids

These tests indicate the incompatibility of clays with the extraneously introduced water, including filtered formation brine and filtered mud filtrate (Keelan and Koepf, 1977). Such tests can also be used to evaluate the effectiveness of clay stabilizers added to workover and injection fluids (Keelan and Koepf, 1977). Keelan and Koepf (1977) state that "Use of filtered workover fluids removes plugging solids and results in evaluation of damage resulting from clay swelling and/or clay-particle movement." The rock-water system is considered compatible when the formation permeability does not decrease by fluid injection. Keelan and Koepf (1977) state that

The clays damage productivity either by swelling in place or by release from their anchor point and subsequent movement to block pore channels. The inclusion of certain ions in workover and injection fluids often offers a relatively inexpensive and effective stabilization of the clays and prevention of productivity impairment.

Keelan and Koepf (1977) presents the test sequence and the equations necessary for determining formation damage for evaluation of the compatibility of the injection and workover fluids with the formation clays. Keelan and Koepf (1977) shows the results of injecting brines with and without KC1 and CaCl2 added. Injecting a brine, rather than the formation brine, into a core sample A reduced the permeability to 50% of its formation brine permeability. Injecting a brine containing 100 ppm KC1 into a core sample B doubled

its formation brine permeability. However, injecting a brine containing 100 ppm CaCl2 reduced the permeability to 50% of its formation brine permeability.

Keelan and Koepf (1977) shows that consecutively decreasing concentrations of KCI and CaCl2 in the injected brines yields permeabilities above the initial formation brine permeability. Keelan and Koepf (1977) concluded that KCI treatment is favorable even though the data appear unusual. Keelan and Koepf (1977) recommend the water-oil relative permeability measurements as a practical approach to damage assessment in core plugs. Keelan and Koepf (1977) express that the fluids compatible with the core material should typically yield the relative permeability curves similar to those shown between the AA' and BB' lines.

Keelan and Koepf (1977) explain that, when a filtered injection brine is injected into a core containing irreducible oil, a specific value of the water relative permeability, denoted by Point E in this article, is obtained. This particular value represents the water relative permeability at the injection-wellbore formation face. Whereas, the water relative permeability at a sufficiently long distance from the well bore is represented by Point B.


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