Changes of flooding reagents' properties under simulated high temperature/pressure conditions in oil reservoirs and their impact on emulsion stability

Abstract

It is of great significance to know the fate of the polymers and surfactants used for enhanced oil recovery (EOR) in oil reservoirs at a relatively high temperature/pressure. In this paper, the changes of the properties of a polymer (partially hydrolyzed polyacrylamide, HPAM) and a surfactant (petroleum sulfonate, PS) were investigated under simulated oil reservoir conditions (a temperature of 45, 60 or 75 °C and a pressure of 10, 15 or 20 MPa). The impacts of the property changes to emulsion stability were also highlighted. The results showed that the hydrolysis degree of HPAM increased from 24.3% to 28.9%, 29.7% and 35.4%, whereas the molecular weight (M_w) decreased from 7.60 × 10⁶ g mol⁻¹ to 5.43 × 10⁶ g mol⁻¹, 4.49 × 10⁶ g mol⁻¹ and 2.87 × 10⁶ g mol⁻¹ as a function of raising the temperature to 45, 60 and 75 °C with 20 MPa, respectively, for a duration of one week. However, the increased pressure showed obvious prevention effects on the degradation of HPAM M_w in the investigated pressure range of 10–20 MPa. There were no changes in the oil–water interfacial tension for PS solutions after high temperature/pressure treatment. The stabilization ability of HPAM to the emulsion decreased markedly after treatment because of the decreased viscosity attributed to the reduction of molecular weight, while that of PS did not change. It is reasonable to speculate that the influence of back produced HPAM to the stability of EOR produced water will be quite different in different oil reservoirs because of the differences in reservoir temperature, pressure and retention time, and therefore different strategies should be considered in treating the produced water from EOR.