Optimization of Wireline Sample Quality by Real-Time Analysis of Oil-Based Mud Contamination - Examples from North Sea Operations

Abstract

Oil Based Mud (OBM) systems are often required to be able to drill a well successfully. Their use generally results in a better quality well-bore and reduced drilling time. Unfortunately, this can also result in increased environmental issues as well as difficulties in accurate formation evaluation. One area of formation evaluation that can suffer greatly when OBM is used is wireline fluid sampling. High levels of the miscible OBM filtrate in the final sample render fluid characterisation results questionable and often useless. To obtain high quality oil samples the sampling method and mud system need to be optimized in order to minimize the contamination level. When an accurate measurement of the level of contamination cannot be made and therefore the amount of miscible filtrate cannot be corrected for, the resulting fluid characterization cannot be trusted. Discrepancies in the current methods of measuring contamination have left many unanswered questions. Furthermore, the resulting reservoir parameters are questionable and must often be discarded. The ability to measure contamination in real-time while sampling offers an opportunity to revolutionize the sampling method, optimize sample quality, and improve the final results. In addition, this offers the possibility for significant savings in operational time. Analyses of oil samples taken in OBM in the North Sea have shown that it is possible to estimate contamination while sampling using the optical properties of the OBM filtrate and the crude oil. Although these estimates may differ from those obtained through contamination measurements at surface, in several case studies addressed in this paper the downhole contamination estimation proved to be more accurate for a given sample than the corresponding contamination measured at surface. This paper examines oil samples from wells drilled with OBM and discusses the ability to predict downhole contamination from their case histories. The research shows that real-time contamination measurements will lead to improved fluid characterization and consequently improved reservoir engineering. Introduction Throughout the history of formation evaluation, the mud used to drill a well often limited the quality of wireline data and samples retrievable from that well. Drilling with an OBM has long been preferable for well quality, well stability, and efficient drilling, but unfortunately also has an adverse effect on some wireline data, particularly wireline fluid samples. In order to optimize wireline fluid sampling (WFS), the use of the Optical Fluid Analyzer* (OFA), a part of the Modular Formation Dynamics Tester* (MDT) or equivalent, has become an essential part of this sampling process to qualitatively predict sample fluid type and quality. The ability to use the optical data from the OFA in a more quantitative manner has been under development for several years1,2,3. This paper explores the use of the OFA and the recent new tool the Live Fluid Analyzer* (LFA), which measures the gas-oil ratio (GOR) during sampling, to determine OBM contamination measurements during WFS.