Simulation of Polymer Injection Under Fracturing Conditions—An Injectivity Pilot in the Matzen Field, Austria

Abstract

Summary Polymer flooding leads to enhanced oil recovery by accelerating oil production and improving sweep efficiency. However, because of the higher viscosity, the injectivity of polymer solutions is of some concern and is important to understand to predict incremental oil recoveries. Achieving high polymer-injection rates is required to increase oil-production rates. In the field test performed in the Matzen field (Austria), polyacrylamide polymers were injected for the past 2 years. Coreflood experiments with these polymers showed a significant increase in apparent viscosity because of the viscoelastic properties of the polymer solutions. Also, severe degradation of the polymer solution at high flow velocities was detected. In addition to coreflood experiments, flow experiments through fractures were performed. In these experiments, shear thinning and limited degradation of the polymer solution were observed and quantified. Detailed polymer-injection simulations were conducted that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and their effects on the fractures were also taken into account as a result of cold-polymer injection. The results of the simulations matched the field data both for waterfloods and polymer-test floods. The simulations revealed two distinct phases during the injection of the polyacrylamide-polymer solution: Injection under matrix conditions in an early phase resulting in severe degradation of the polymers Injection under fracturing conditions after the formation parting pressure is reached, leading to limited degradation of the polymers The calibrated model was used to investigate the impact of polymer rheology and particle plugging on injectivity and fracture growth. The results of the field test and the simulations indicate that screening of fields for polyacrylamide-polymer projects needs to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in screening such as oil viscosity, water salinity, reservoir temperature, and reservoir permeability.

Polymer Flow in Porous Media: Relevance to Enhanced Oil Recovery

“…In some polymer flooding projects, measured injectivity may differ significantly from the simulation or analytical forecast. These unexpected injectivities may be due to the occurrence of mechanical degradation [82,85,86], induced fractures [87][88][89], or even inaccurate analytical models for calculating in-situ rheology and predicting extensional viscosity.…”

Mechanical Degradation of Polymers During Injection, Reservoir Propagation and Production - Field Test Results 8 TH Reservoir, Austria

“…However, to achieve high enough injection rates for economically attractive projects, polymers are in a lot of cases injected under fracturing conditions (e.g. van den Hoek et al 2012, Manichand et al 2013, Zechner et al 2015. For these conditions, no severe degradation was measured in laboratory experiments in fractures (Zechner et al 2013).…”

Operational Challenges and Monitoring of a Polymer Pilot, Matzen Field, Austria

“…As in other EOR tests (Zheng et al 2011;Wylde et al 2013;Rambeau et al 2014;Al Kalbani et al 2014), several operational challenges have been experienced in separation and water-treatment facilities resulting from polymers.…”