Estimation of Polymer Retention from Extended Injectivity Test

Abstract

The aim of this study was to reduce risk in polymer flooding projects. Specifically, this study investigates polymer retention and viscosity losses. The study reservoir is a fluvial type reservoir with friable/unconsolidated sandstone units that are saturated with viscous oil. The reservoir is located in the south of Argentina. Retention and viscosity losses are the key parameters in designing a polymer flooding. They slow down the polymer velocity and deplete the polymer slug leading to a significant impact in the oil banking formation and therefore in the oil response. In friable/unconsolidated reservoir rock samples the usual laboratory procedure for retention estimation is fraught with complications and errors and may lead to unreliable results. We used a 20 month single-well injection/back-production test. And we monitored the sweep efficiency with time-lapse formation resistivity logging. The well schedule included, 5 months of water injection, three months of polymer injection and 12 months of back-production. We used an innovative inline viscometer to measure viscosity in the backflow stream at anaerobic conditions. This procedure avoided the problems of chemical degradation due Fenton chemistry with the oxygen scavenger. We measured the concentration with two methods, COD (Chemical Oxygen Demand) and bleach method. The back-produced polymer solution showed relatively low viscosity losses as compared to that of the injected solution. The interpretation of the polymer concentration measurements with a detailed simulation model led to retention bounds between 35 to 260 micro-grams of polymer per gram of rock with heterogeneous retention depending on the facies. This is sevenfold the value estimated from packs of crushed reservoir core material and threefold the value from coreflood studies in reservoir samples. This study has allowed us to adjust the forward planning and understand the retention behaviors in distributed clay fluvial formations. This methodology can provide low cost reliable estimations of polymer retention at a larger scale than corefloods.

Assessment of Polymer-Induced Formation Damage Using Microfluidics

“…Laboratory experiments confirmed the existence of plugging behavior beyond a critical injection rate. A single-well injection/back-production implementation of polymer flooding showed important discrepancies in the polymer retention in the reservoir compared to laboratory tests using crushed material samples and coreflood samples (Juri et al, 2015). Polymer injection tests at the Bhagyam field experienced a steady increase in the injection pressure, possibly due to wellbore plugging (Kaladhar Sharma et al, 2016).…”