All wells are susceptible to formation damage at any time during the life of a well. Some damage sources are drilling fluids, cement filtrates, water and/or emulsion blocking, oil wetting of silicate surfaces, "dirty" treating fluids, and clays. Clays may be considered a major source of permeability reduction. This damage can occur when a water foreign to the formation contacts the clays, causing them to break loose and migrate with fluid loss. Subsequent bridging of clay particles at flow restrictions in the rock can then cause a decrease in permeability.
Completion techniques can vary considerably from one field to another as methods should be devised to fit particular conditions. Good completion procedures depend upon having reliable well data available, making use of past experiences, and using clean (filtered) past experiences, and using clean (filtered) an properly treated workover and stimulation fluids.
Permeability damage often occurs with the initial completion of a well. However, this damage usually exists only a short distance into the formation and can be removed with relatively small volumes of various types of acid solutions.
Where a well is to be stimulated, a better procedure can be developed if cores are procedure can be developed if cores are available for tests. The results of these tests will help develop the type of fluid to use for the treatment. Two of the tests that should be conducted are as follows.
The selection of a surfactant to be added to the stimulation fluid that will help to prevent emulsion development and also provide very low interfacial tension values provide very low interfacial tension values between the fluid and hydrocarbons in the formation. The latter is essential in the recovery of the stimulation fluid (usually aqueous) from formation flow channels. The surfactant should also leave the rock water wet.
The analysis of the cores to determine mineral and clay content is very important. If enough clay is present for the formation to be considered to be water sensitive, 1- to 2-percent potassium chloride or ammonium chloride can be added to the water-base stimulation fluid to minimize possible permeability damage due to clays.