Correcting for Wettability and Capillary Pressure Effects on Formation Tester Measurements

Abstract

Abstract Conventional formation tester interpretation techniques have long assumed that the measured tester pressure is identical to the pressure of the continuos phase in the virgin zone of the formation. As such, a series of pressure measurements at different depths would be expected to consistently yield a pressure gradient corresponding to the density of the formation fluid. Recent work by the authors of this papers as well as by others has shown that the formation testers will actually measure the pressure of the continuos phase present in the invaded region, typically the drilling fluid filtrate. The measured tester pressure is, thus, different from formation pressure by the amount of capillary pressure. This capillary pressure has been shown to be a strong a function of the wetting phase saturation. The effects of the rock wettability and capillary pressure on wireline formation tester measurements are manifested as pressure gradient changes and/or fluid contact level changes on many logs, particularly those recorded with oil-based mud in the borehole. This paper summarizes the effects of wettability and capillary on wireline formation measurements and investigates in detail the possible techniques for recognition and estimation of and correction for those effects. The older techniques rely on the use of core capillary pressure data log-computed flushed zone saturations, but they can often yield inconsistent results. Amongst the more innovative techniques suggested in this paper is the use of NMR measurements to estimate the magnitude of capillary pressure effects and hence correct the measured tester pressure. Also discussed in the use of the pump-out capability of the Modular Dynamics Tester (MDT™) to estimate the capillary pressure effect by making measurements before and after the removal of drilling mud filtrate. This allows accurate correction for capillary pressure effects, or better still, the elimination of the need for the correction altogether. Introduction In an oil reservoir, water will normally compete with oil and gas for pore space. This is because water was present in the pores before oil migrated into the reservoir. Thus, at the same depth in a formation, pressures will be different depending on whether oil or water is filling the pores. The amount of pressure difference between the two fluids is largely controlled by pore geometry, rock wettability and the interplay of capillary pressures between rocks and fluids. Capillary pressure (Pc), represents the pressure differential that must be applied to the nonwetting fluid in order to displace a wetting fluid. The value of capillary pressure is dependent on the saturation of each phase, on which phase is the wetting phase, and on the shape and size of the pores and pore throats. Wettability is the property of a liquid to stick to and spread onto a solid surface. It is normally quantified by the value of the contact angle, such that a value less than 90 degrees indicates a water-wet system, and a value greater than 90 degrees indicates an oil-wet system. The following paragraphs take a closer look at the wettability and capillary pressure concepts.