12.6.1 Drilling Fluid Selection
Although drilling fluids are generally selected for their drilling properties, a consideration of formation damage sensitivity should also guide mud selection. For example, formations known to be sensitive to low salinity brine can be drilled with a NaCI brine mud or KCI-polymer mud. Experience has shown that these muds can be less damaging to formations with sensitive clays, leading to easier production testing and well completion.
Although approach to minimizing mud damage involves maintaining low fluid loss properties in the mud, thereby confining the invaded zone close to the wellbore. Low filtration characteristics require careful monitoring of the mud system, with the addition of
additive and deflocculants as necessary. Maintaining the clays in a deflocculated state increases their effectiveness at building thin, impermeable filter cakes. If this can be accomplished, routine perforating may be sufficient to penetrate the shallow damage zone.
12.6.2 Workover Fluid Salinity
Formation damage from clay swelling and migration can be avoided during workovers by exploiting some established properties of clays. Clays will tend to resist changing from their native geologic equilibrium state, providing that external disturbances are not too severe. This applies to both swelling and dispersing, where it has been shown in core tests that gradual reductions in salinity are less damaging than abruptly imposed decreases (see Figure 20). General experience suggests that clays which formed in high salinity connate brines (50,000 ppm +) can withstand decreases in salinity of 50% or more, and even greater final reductions can be tolerated if taken stepwise. However, general experience also suggests that some clay disturbance will result in high salinity formations exposed to NaCI brines lower than about 4000 ppm in salinity regardless of how slowly salinity is lowered.
Factors such as maximum tolerable salinity drop per step and damage threshold salinity are certainly dependent upon the rock and the formation brine. Nevertheless, they provide us with general guidelines for field application. For example, based on the above observations it is recommended that workover fluid salinity not be sharply different from salinity. This guideline permits us some leeway, in the sense that 50% reductions are often tolerable, whereas a 95% reduction is usually too drastic. Fresher water formations, characterized by 5000 ppm salinity or lower, generally are not even sensitive to fresh water.
Figure 20. Effect of Gradual Salinity Reduction on Permeability
12.6.3 Brines To Stabilize Clays
Clays can be stabilized against low salinity swelling by exposure to calcium brine. Core material pretreated with calcium brines is typically insensitive to fresh water damage.
Other ions such as NH4
+ and K+ may also be somewhat effective at preventing fresh water damage, but this has not been conclusively demonstrated.
Damage from dispersion of non-swelling clays by fresh water can also be prevented by treating these clays with calcium brine. As in the case of swelling, there is evidence that NH4+
and K+ also help to inhibit dispersion.
Although there are a variety of theories and observations concerning clay sensitivity, it seems clear that most damage can be avoided by preventing drastic decreases in salinity. It is also well established that calcium brines will desensitize clays against swelling and dispersal damage. These observations are the basis for establishing field guidelines governing compatibility of workover fluids with formation clays.
12.6.4 Clay Stabilizers
Clay stabilizers are chemicals designed to eliminate the tendency of clays to swell and disperse when exposed to low-salinity brine. These molecules function by adsorbing tightly onto the clays, thus preventing the expansion of the ionic layer upon introduction of fresh water.
Experiments confirm that some clay stabilizers are effective at preventing low-salinity damage. However, experiments also show that currently available clay stabilizers are not effective at preventing fines migration caused by fluid flow. Figure 21 shows the effect of a clay stabilizer on a laboratory core under two flow rate conditions for the case of fresh water exposure.
At the lower velocity, the clay stabilizer prevented clay damage and the core retained 100%
of its permeability, even after exposure to fresh water. However, above a critical flow velocity, the permeability declined in spite of the presence of stabilizers. Thus, clay
stabilizers should only be used where formations will unavoidably be exposed to fresh water.
Figure 21. Pretreatment with a Clay Stabilizer Prevents Only Fresh Water Damage
12.6.5 Avoid Incompatible Brines
As discussed earlier, some combinations of calcium workover fluid and formation brine can lead to scale damage in the formation. Where possible, a water analysis should be obtained to determine this tendency. Specifically, there are methods to predict whether the HCO3
content of a reservoir brine will scale if exposed to calcium workover fluid.
12.6.6 Surfactant Selection
The use of surfactants which will not cause adverse wettability changes is also important.
Specifically, sandstone formations, which normally are negatively charged, should not be exposed to positively charged cationic surfactants. Carbonate formations are positively charged and therefore should not be treated with negatively charged anionic surfactants.
12.6.7 Drawdown
The drawdown, or pressure differential from the formation into the wellbore, can be responsible for causing mechanical fines migration, especially in poorly consolidated formations. This type of fines and clay migration cannot be prevented through the uses of clay stabilizers. It may be necessary to limit drawdown and fluid production if fines-migration damage and sand production is a severe problem.
12.6.8 Fluid Loss Control
The ideal approach to workover fluid quality is to maintain well filtered fluids to prevent damage from fines introduction into the formation. However, under realistic field conditions, it is not often possible to achieve a high level of fluid cleanliness. This problem is compounded if permeable zones are being exposed to the fluid. An approach to this problem is to intentionally add acid-soluble fluid loss control particles to the fluid to minimize leakoff and damage. These particles can then easily be removed with acid. This procedure will be discussed in more detail in the workover fluids section.
12.6.9 Injection Water Quality
Formation damage in injection wells is often characterized by recurring injectivity declines requiring periodic treatment. This is usually attributable to solid particle or oil injection, which ultimately leads to plugged perforations and/or creation of a near wellbore oil saturation. Although it is not practically possible to remove all solids and oil from injection water, maximizing water quality within economic constraints will significantly reduce the frequency of cleanout and damage removal operations. The cost of frequent treatments must therefore be balanced against the cost of improved facilities.