Downhole Fluid Analysis and Fluid-Comparison Algorithm as Aid to Reservoir Characterization

Summary In recent years, formation-sampling and formation-testing tools have provided a variety of new downhole optical measurements for downhole fluid analysis (DFA). DFA involves an in-situ measurement of optical absorption spectra used to compute properties such as hydrocarbon composition and gas/oil ratio (GOR). Abrupt changes in these fluid properties with depth may be markers for reservoir compartmentalization. However, hydrocarbon differences can be identified reliably only when the significance of uncertainties from measurement and the oil-based mud (OBM) filtrate have been taken into account. Recently, an algorithm called the fluid-comparison algorithm (FCA) was developed to address this issue. The FCA propagates uncertainties in optical measurement and contamination into uncertainties in fluid properties, such as color, composition, and GOR. The output of the FCA is the probability that two fluids are statistically different. Real-time application of the FCA can optimize capture of downhole-fluid samples and generation of a continuous downhole-fluid log representing the fluid complexity in the reservoir. In addition, by identifying abrupt changes in fluid properties that occur with depth, the FCA may in some circumstances be an assay for reservoir compartmentalization. In this paper, we briefly review the theory of the FCA. The strengths and limitations of the technique for an improved understanding of reservoir architecture and fluid complexities are presented in two case studies.