Moving Beyond the Capillary Suction Time Test

Abstract

Abstract The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material, and the capillary suction time (CST) test has become a standard test method. However, the CST test is designed to measure particle flocculation and specific filtration, and as such is not constructed to differentiate the relative impact of either clay swelling or wetting alteration effects. The CST test produces an amalgamated result of several processes and cannot be scaled back to one particular process. While the CST test has been used to gain an overview of fluid issues, it also introduces a medium (paper) that is far different from anything found in a reservoir. The rate of imbibition into the paper will be affected by fluid/paper interactions. Efforts to model results from CST tests have not been successful; its results cannot be plugged into a model. The millions of CST tests performed have not enhanced the industry’s insight into rock/fluid interactions. Given that the CST test has no theoretical basis and given the lack of standardization with respect to both testing methodology and the interpretation of results, there is a great need for an improved test method. In order to evaluate the impact a treatment fluid has on the reservoir rock, the actual wetting conditions need to be determined. Treatment fluids and additives, e.g. clay stabilizers and surfactants, can alter the wetting characteristics of the rock surface. A direct measure of wettability is the contact angle. We have identified a new method to determine the dynamic advancing contact angle on a small amount of sample that allows us to quickly and quantitatively explore the alteration of the rock wettability by the fluid and additives. Results from the new test method are quantitative and can be plugged into a model. We applied this simple and theoretically sound test method to material from different formations, using a multitude of different fluids and evaluated how the treating fluid interacts with the formation material. We show how the new method can determine the tendency of the rock to imbibe fluid.