Viscous Oil Dynamics Evaluation for Better Fluid Sampling

Abstract

Abstract Productivity potential evaluation in viscous reservoirs has been difficult in the past due to difficulties in native fluid sampling and in-situ dynamic formation testing evaluations. This is the result of the high oil viscosity and the unconsolidated sands in which they are usually deposited, which create limitations to natural flowing and smooth well testing / production. There is no unique answer to the main question "how do we sample heavy oils in unconsolidated sands". However, fromthe experience Schlumberger has acquired during years, several modifications have been done to the wireline formation testers (WFT)1, such as the Modular Formation Tester (MDT*), and new modules have been developed which, linked to new best practices, have allowed high viscous oil sampling and in-situ formation testing. Some of the new modules and practices include, the extra large diameter (XLD) probe, dual packer with customized gravel pack screens, extra high-pressure displacement unit pump for low flow rates, advanced down hole flow analysis monitoring (DFA*) and special sampling techniques. In this paper, we present a methodology, which integrates formation tester pressure and water-cut measurements with detailed reservoir characterization from logs to better understand the viscous oil dynamics in sandstones reservoirs in order to optimize fluid sampling. A commercial reservoir simulator ECLIPSE* in fully implicit, black oil mode is used to simulate the multiphase flow during WFT pumping. Around the wellbore very fine grids are used, which, linked to a multi-segmented wellbore option, allows to model the clean out (contamination level versus time curve) and fluid drainage for different scenarios of oil viscosity, reservoir anisotropy, drilling fluid invasion, flow rate and WFT position relative to the top boundary. The modeling results were validated using WFT field data with different rock and fluid properties. Some correlations were developed for field use that estimates filtrate contamination as a function of clean out time for several WFT modules. A good understanding of the limitations and benefits of each tool under each scenario contributes to a better collaboration in the design and optimization of sampling jobs (best practice and calibration of available analytical planners for field use). Introduction Formation fluid sampling early in the life of a well ensures that necessary information is available for reservoir completion planning and decision-making. This is particularly important in heavy oil environments, where flow assurance is a major concern (Fig.1).