Systematic Development and Laboratory Evaluation of Secondary Polymer Augmentation for a Slightly Viscous Arabian Heavy Reservoir

Abstract

Abstract Polymer augmentation of waterfloods is the application of polymer flooding in a secondary mode prior to significant water injection. Polymer flooding is a mature enhanced oil recovery (EOR) technology with a distinctive advantage where an existing waterflooding infrastructure exists. In this work, we design and evaluate secondary polymer augmentation for a slightly viscous Arabian Heavy reservoir at the laboratory scale. We follow a systematic and comprehensive workflow to characterize the polymer performance and behavior to gain sufficient level of understanding for future simulation-based scale-up. We firstly capitalize on previous long-term stability results of several polymers in similar high temperature and high salinity conditions to select a potential polymer for the current application. We characterize the polymer rheology at reservoir conditions. Then, we adopt a fractional-flow based approach for initial optimization of polymer concentration. Traditionally, rough measures such as ratios of viscosity or endpoint mobility are used to set the initial polymer concentration used in laboratory evaluation. This could lead to simulation-based optimals that are much different and hence are ill-based since they are actually outside the models domain of prediction/confidence. The adopted fractional-flow workflow addresses this limitation and minimize the number of future experimentation. The workflow uses the reservoir previously established two-phase flow functions and the polymer measured rheology as inputs while accounting for both heat and shear degradation to optimize concentrations based on polymer utilization factor as an objective function. Later, we select several core-plugs from the same well based on porosity-permeability cross plots, Winland rock-typing, and nuclear magnetic resonance (NMR) pore-throat distributions. We conduct a set of three oil-displacement experiments across three different rock types at reservoir conditions and using composites of two-plugs that have been aged for 8 weeks. Dean stark analysis followed to assure consistency of remaining oil estimates. Finally, we perform a single-phase displacement experiment to characterize the polymer in-situ rheology, injectivity, adsorption, and inaccessible pore-volume. The experiment consists of three phases (water/polymer/water) each ran until pressure stabilization and at four different injection rates. A cover tracer was co-injected with the polymer. Polymer concentrations in effluents are estimated based on total organic content (TOC) analysis and NMR spectroscopy while tracer concentrations are estimated based on gas chromatography (GC). Fractional-flow based optimization suggested an initial target viscosity of 4 mPa.s. At this viscosity, we achieve optimal utilization for the selected polymer while accounting for the expected surface and wellbore mechanical degradation as well as the in-situ long-term thermal degradation. At those levels of degradation, this target viscosity can be achieved with an injection concentration of 5500 mg/L. In terms of recovery, all three oil displacement experiments conducted using a displacing solution of 4 mPa.s demonstrated the significant potential of polymer augmentation in terms of both recovery acceleration and enhancement at a given threshold of watercut or pore-volume. For instance, after 1 pore-volume, the incremental recovery averaged around 15% OOIC (original oil in core). Finally, the single-phase experiment conducted at the suggested injection concentration further supported the selected polymer potential from injectivity and consumption standpoints: the polymer affects a manageable residual resistance of around 3 and exhibits a reasonable dynamic adsorption of 0.28mg/g-rock.