Formation Evaluation of Triassic Naturally Fractured Carbonates In British Columbia

Abstract

Abstract Triassic naturally fractured carbonates have proved to be very prolific in British Columbia. The fractures are of tectonic origin and were probably generated during the Laramide orogeny which created a series of compressional type structures. The formation evaluation was conducted with a dual-porosity model which allowed estimates of matrix and fracture porosities from logs. Water saturation in matrix and fractures were calculated with the use of a statistical procedure without previous knowledge of water resistivity. In addition, the interpretation led to estimates of bitumen content and percentages of siltstone, limestone and dolomite. The determination of the bitumen content is very important because bitumen can reduce effective permeability to gas quite significantly. Log Interpretation Well log analysis of Pardonet-Baldonnel formations was carried out with the use of a dual-porosity model which takes into account the presence of natural fractures and matrix porosity(1). Water saturation was calculated with the use of the P1/2 statistical procedure. P1/2 has a normal distribution for intervals that are 100% saturated with water. Hydrocarbon-bearing intervals deviate from the normal distribution. Basic Approach In this process, Archie's basic formation evaluation equations: Equations (available in full paper) In the above equations Φ?stands for total porosity (fraction), m is the porosity exponent of the composite system of matrix and fractures, I is the resistivity index, Rt is the true resistivity, A is a function of shaliness, F is the formation factor, Rw is water resistivity at reservoir temperature and "a" is a constant. Analysis of Equations (4) and (5) indicates that (1) a crossplot of porosity or the response of a porosity log vs. Rt or (2) a crossplot of porosity vs. Rt/ Ash on log-log coordinate paper should result in a straight line with a slope of -m for zones with constant aRw and constant I (Figures 1-A and 1-B). For reservoirs with natural fractures, the value of m is smaller than the cementation exponent mb, determined from a matrix plug in the laboratory at simulated reservoir overburden conditions. This is reasonable because open unhealed fractures produce a reduction in tortuosity and cementation(4). In many cases, it is possible to carry out the evaluation by crossplotting (Δt - Δtm) vs. Rt or (Δs - Δb) vs. Rt on log-log paper. In these crossplots Δt is sonic transit time as determined from the sonic log, Δtm is sonic transit time at zero porosity, ?s is grain density and Δb is bulk density. When working with sonic logs in fractured carbonates the usual values of Δtm and Δtf no longer correspond to well defined physical parameters as they do in the case of the well known Wyllie(7) formula. Rather, these parameters have to be determined specifically for each case. We have found through experience that the sonic log is very useful in enlarged boreholes. The value of m is determined by calculating the slope of the line drawn through the lower points in the log-log plot.