Mechanistic Simulation of Polymer Injectivity in Field Tests

Abstract

Summary Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates. The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times. One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.

The Performance of Polymer Flooding in Heterogeneous Type II Reservoirs—An Experimental and Field Investigation

“…This is agreement with the existing knowledge that the increase in the bottomhole pressure during the early stage of polymer injection can be attributed to the shear-thickening rheology at high velocities experienced by viscoelastic HPAM around the wellbore and the permeability reduction caused by polymer adsorption [24]. Regarding type I reservoirs with a high permeability, we can conclude from these single-phase flow behaviors that the injection performance of polymers in type II reservoirs are all associated with permeability, the molecular weight of the polymer, and the designed polymer concentration, where the injection capability is remarkably affected by permeability, followed by polymer concentration and polymer molecular weight.…”

“…The pressure slope of the two well groups are essentially equal, and compared with the baseline, the maximum pressure increases of well group 1 and well group 2 were 78.24% and 51.57%, respectively. This result indicates that the pressure rise by permeability reduction resulting from retention is stabilized with the injection of a polymer slug [24]. Furthermore, the average incremental recovery of well group 1 was 14.4% (OOIP) better than that of water flooding, which exceeded the expected effect, and the comprehensive water cut still remained within 88% after the polymer slug was injected.…”

“…To extend the laboratory results to field scale, a mathematical model that is capable of considering important mechanisms that influence injectivity has been proposed, and systematic simulations of injectivity, which declines during polymer flooding, were performed recently by Lotfollahi et al [24]. Although the injectivity model can calculate the injection pressure in both the coreflood and field tests, from which, an understanding of the contribution of different phenomena to the pressure rise in polymer-injection wells can be obtained, the filtration model, which was coupled with a polymer-rheology model to simulate the permeability reduction, did not consider the impact of flushing of "polymer junk" removal; the successful case used a sandstone reservoir, which also has a high average porosity and high average permeability.…”

Supramolecular Polymer-Surfactant System for Heavy Oil Recovery

“…While, the residual resistance factor (RRF) measures the increased pressure drop across the porous media due to polymer retention (mechanical entrapment and polymer adsorption) [5,6,19,29,[37][38][39][40][41][42][43][44]. system, while for the baseline AP1 polymer, the RF value plateaued out at an average value of 2.0.…”

“…AP1 was 0.5, while the average end RRF value for the SAP-AP1 system was 0.02, suggesting insignificant pore plugging and/or permeability reduction due to polymer retention, which is expected in unconsolidated and/or high permeability porous media [37,42].…”