Quantitative mixing rules for downhole oil-based mud contamination monitoring in real time using multiple sensors

Abstract

Abstract Accurate quantification of oil-based drilling mud (OBM) filtrate contamination of hydrocarbon samples is still one of the biggest challenges in formation fluid sampling with formation testers. There exist contamination quantification techniques, but they can be technique sensitive, lack a confident level of quality control and apply only to a limited combination of probe types and formation fluid types. In particular, current techniques rely on an assumed absence of mud filtrate coloration at relevant optical channels and on sufficient optical density contrast between mud filtrate and virgin fluids. Such assumed fluid properties may not materialize when, for example, drilling muds are reused in multiple wells or when virgin fluids exhibit little color due to the absence of asphaltenes. In this paper, new mixing rules have been developed for mass density and shrinkage factor and for the newly defined “ f -function” and “ q -function”. The f -function, also referred to as the modified gas/oil ratio, is essentially a combination of gas/oil ratio with shrinkage factor. Similarly, the q -function is referred to as modified composition and is a combination of composition with mass density. OBM filtrate contamination in volume fraction, optical density, f -function, mass density, shrinkage factor, and q -function at a specified downhole sampling station have been found to be mutually linearly related as predicted by the mixing rules. The mutually linear relations are further confirmed by laboratory data for different mixtures of mud filtrate and formation fluids. Application of these mixing rules enables accurate OBM filtrate contamination in hydrocarbon samples if the filtrate properties and virgin fluid properties can be determined. A new methodology has been developed to determine the properties of the virgin formation fluid and mud filtrate, which are referred to as endpoints. The mud filtrate properties are obtained by extrapolating the mutually linear relations established from the cleanup data to zero gas/oil ratio or other known filtrate values such as zero methane composition, and/or zero optical density at specified wavelengths. The virgin fluid properties are determined by the power-law fitting of cleanup data coupled with the flow regime identification which is confirmed by large number of downhole fluid analysis datasets from wireline formation testers and numerical simulation. This novel methodology enables accurate quantification of the OBM filtrate and pure virgin formation fluid. Furthermore, the self-consistency of using multiple independent sensors provides confidence and greatly improves the robustness and quality control of OBM filtrate contamination monitoring downhole. Finally, contamination results can be expressed in volume or weight percent and as live fluid or stock-tank liquid fraction for easy comparison to laboratory results. A latest generation downhole fluid analysis (DFA) tool was employed to measure fluid properties downhole in real time on more than 30 DFA stations acquired with either conventional probes or 3D radial probes. The new methodology was applied to each of the acquired datasets. All the results from the new method are in good agreement with the results of the laboratory analysis.