TX 75083-3836, U.S.A., fax 01-972-952-9435.
AbstractWorldwide, carbonate oil-water transition zones contain vast amounts of producible oil. Yet, traditional approaches to open-hole formation evaluation often fail to predict how much oil should flow from them, or even the location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading mud filtrate and formation oil, to result in the following unusual yet often observed behavior: 1) negative pressure gradients, 2) waterlike gradients significantly above the free water level, 3) significant shifts in the measured pressure potentials between the lower and upper part of the transition zone, 4) gradients implying an oil-density different to that which is expected. Supercharging effects are shown to be unimportant to the discussion. Both wells drilled with water based mud and oil based mud are considered. It is shown how it is usually possible to produce oil from a zone which has a water-like pressure gradient and low formation resistivity. The theory is supported by detailed analysis of examples from flow simulations, which recreate the well known field cases referred to above. Guidelines are presented on how to interpret traditional open hole pressure measurements in a carbonate oil-water transition zone to determine the free water level and the locations where oil should flow, and on how to improve on these interpretations by performing more advanced formation testing procedures, some of which are based upon new technology.