Polymer Solution Injection – Near Wellbore Dynamics and Displacement Efficiency, Pilot Test Results, Matzen Field, Austria

Abstract

A number of reservoirs in the Vienna Basin in Austria might benefit from polymer solution injection. In November 2011, a polyacrylamide polymer injection pilot commenced for the 8 th Torton Horizon reservoir to reduce the uncertainties related to this technology.To further improve the understanding of the polymer solution injection, laboratory experiments and numerical simulations were performed.The results of the injection test and laboratory experiments show that two phases can be distinguished: first, a phase of polymer solution injection below the Formation Parting Pressure (FPP) can be observed. This phase is characterised by high flow velocities in the near-wellbore area, resulting in severe degradation of the polymer, and a slower rise of the pressure than expected for undegraded polymers. In the second phase, the FPP is reached and fractures are generated. In this phase, the polymer solution exhibits shear-thinning behaviour in the fractures. Owing to significantly lower flow velocities in the formation, degradation of the polymers is limited. Phase one is usually short in comparison to phase two.To achieve sufficient polymer solution injection rates for an economic project without degrading the polyacrylamide polymer, inducing fractures by injection is required for the reservoirs in the Vienna Basin. Hence, screening of fields has to include geomechanical properties of the reservoir sands and surrounding shales. Also, the risk of fracturing outside of the formation has to be assessed. In addition, the values of the FPP of the reservoir sands and surrounding shales and the direction of induced fractures should be determined. Furthermore, the injection water quality in terms of fines and oil content has an impact on the fracture growth and should be evaluated.

Historical and recent observations in polymer floods: An update review

“…This strategy was considered for Matzen polymer flood pilot. Injection rates were kept constant above the frac gradient constrained by the wellhead pressure operating conditions tapering polymer concentrations (Clemens, T., Deckers, M., Kornberger, M., Gumpenberger, T., & Zechner, M., 2013;Lüftenegger et al, 2015).…”

“…Under the conditions of injecting below the FFP, the near wellbore velocity increases which could result in polymer degradation. On the other hand, injecting above the FFP could create induced fractures with high conductivity over some existence reservoir heterogeneity could result less polymer degradation (Clemens et al, 2013), but monitoring its growth with respect to high sweep efficiency may become a challenging task. Furthermore, since polymer viscosity is a function of the shear rate and correspondingly function of velocity, during the injection and shut-in periods (Fall Off Test) its viscosity will be different at the same distance from the wellbore or more precisely, its transient behavior for injection and shut-in periods will not be the same at the same distance from the wellbore (Mahani et al, 2011).…”

Assessment of Polymer Injectivity with Regards to Viscoelasticity: Lab Evaluations towards Better Field Operations

“…In other words injectivity and viscoelasticity represent a clear conflict, when designing a polymer project concerns. Despite some authors reference to a viscoelastic effect due to flow velocities in the near-wellbore (Clemens et al 2013), most likely the reference should be made to elongational behaviour. On the other hand although the TDS in this investigation are only between 4 -7 g/L, the relaxation times are significantly reduced by salinity and temperature effects.…”

Numerical simulation of the impact of polymer rheology on polymer injectivity using a multilevel local grid refinement method

“…This case is aimed to analyze the behavior of the LGR in the presence of a planar fracture near the injector, which may often be encountered during polymer injection projects (Manichand et al 2013;Clemens et al 2013). We assume that the reservoir has the same condition as case 1 except that there is a fracture initiated from the well block of the injector.…”