Introduction
Treatment fluid selection in sandstone formations is highly dependent on the mineralogy of the rock as well as the damage mechanism. Hydrofluoric (HF) acid is typically used to dissolve the damaging silicate particles. Nonacid systems are sometimes used to disperse whole mud and allow it to be produced with the treating fluid. The criteria for selecting the treating fluid are mineralogy, formation damage mechanism, petrophysics and well conditions.
Formation mineralogy
Compatibility and sensitivity
Compatibility of the formation minerals to the various treating fluids and their additives is a significant issue when selecting fluids for acidizing. Compatibility implies that permeability does not decrease when the treating fluid contacts the formation. This concept of compatibility applies especially to sandstones, where potentially damaging reactions may occur.
Compatibility and sensitivity are related concepts. As stated by McLeod (1984), a successful matrix treatment depends on the favorable response of the formation to the treatment fluid. The treating fluid, therefore, must remove existing damage without creating additional damage through interactions with the formation rock or fluids. A formation is sensitive if the reaction between the rock minerals and a given fluid induces damage to the formation.
The sensitivity of a formation to a given fluid includes all the detrimental reactions that can take place when this fluid contacts the rock. These detrimental reactions include the deconsolidation and collapse of the matrix, the release of fines or the formation of precipitates. The precipitation of some damaging compounds cannot be avoided. Treating and overflush fluid stages are sized; so, there is sufficient volume to push potential precipitates deep enough into the reservoir to minimize their effects because of the logarithmic relationships between pressure drop and distance from the wellbore.
Sandstones can be sensitive to acid depending on temperature and mineralogy. Ions of silicon, aluminum, potassium, sodium, magnesium and calcium react with acid and can form precipitates at downhole temperatures, once their solubility product is exceeded. If these precipitates occur in the near wellbore area, they can damage the formation. Sensitivity depends on the overall reactivity of the formation minerals with the acid. Reactivity depends on the structure of the rock and the distribution of minerals within the rock, i.e., the probability of the acid reaching the soluble minerals.
The sensitivity of sandstone will also depend on the permeability of the formation. Lowpermeability sandstones are more sensitive than high-permeability sandstones for a given mineralogy. Acid formulations should be optimized on the basis of a detailed formation evaluation (Davies et al., 1992, Nitters and Hagelaars, 1990).
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