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Abstract

Experimental data of resistivity index and oil-brine capillary pressure on sandstone and carbonate rock samples from 4 reservoirs are reported. Laboratory equipment using actual fluids at reservoir conditions has been developed. The capillary drainage was achieved with the porous-plate method and fluid saturation along the core was checked for uniformity by conductivity measurements with a four-electrode system. For each rock sample, the resistivity index and capillary pressures were measured first with refined oil and then with crude oil. In addition, wettability indices were determined using Amott's tests. The resistivity/water-saturation law is well fitted by Archie's law except for vuggy carbonates. In this case, the resistivity/ water-saturation plot consisted in two straight line segments in log-log coordinates. The Archie's n-exponent values obtained with crude oil were different than those determined with refined oil except in one case. The n-value increases as the rock becomes more oil-wet. The maximum increase of n-value, from 1.68 to 2.19, was observed for one carbonate, initially neutral and becoming oil-wet during drainage with the Crude oil.

Introduction

The water saturation in oil reservoirs is generally estimated from resistivity well logs. The interpretation of these logs is based on two equations worked out by Archie:

(1)

(2)

in which FR is the formation factor and IR is the electrical resistivity index. Equations (1) and (2) were determined for strongly water-wet clean formations (sandstone or unconsolidated sand with no clay). Here, a value of 2 for m and for n generally gives acceptable results for calculating the water saturation, Sw, determined by the following equation:

S = [ x ] w

resulting from the combining of Equations (1) and (2).

The values of coefficients m and n are mainly obtained from laboratory tests performed on samples assumed to be representative of the reservoir to be investigated. But such tests are usually performed with simulated fluids and under ambient laboratory conditions, which differ greatly from reservoir conditions (pressure, temperature, effective stress, etc.). The values of m and n obtained by such tests and applied without correction to interpret resistivity logs sometimes lead to Sw values that contradict the ones obtained by other methods (preserved core analysis, etc.) or are incompatible with production observations. production observations. A great deal of research has been done on the influence of operating conditions (effective stress, temperature) on the measurement of the formation factor, hence on m. Reference 8 contains a detailed bibliographic study of this aspect. For nonclayey rocks, the influence of temperature is almost nil on the formation factor. In general, the increase in FR is greater than that linked solely to the reduction of . Hence m depends on the effective stress.

The influence of operating conditions on the IR/Sw law and thus on n has received much less attention. This is probably linked to difficulties in performing truly representative laboratory experiments. As for m, it seems that the influence of temperature on n is slight or negligible, except for clayey rocks. The effective stress can cause an increase or decrease in the value of n. The level and direction of the variation of n depend on the type of rock (sandstone or carbonate) and on how the effective stress. is restored. Initial research on the influence of wettability on the resistivity/water-saturation law was done by making the pore surface entirely hydrophobic by a chemical treatment (Dri-film, silicone-containing products, etc.). Extremely high values of n (1.5 to 10 and sometimes even 20) measured under such conditions were strongly contested by log analysts because they led to resistivities of 10(6) to 10(9) oh m, which are values never encountered in reservoirs.

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