Summary Oxidative degradation of polymers is a serious concern in their field application for enhanced oil recovery (EOR). This study is an attempt to resolve some of the discrepancies in the literature regarding the occurrence and extent of this degradation, as well as to present a coherent framework for discussing the multitude of possible radical reactions. Sodium carbonate and bicarbonate are demonstrated to play a key role in stabilizing polymer against multiple reported sources of degradation, and it seems likely that this is caused by their effect on iron solubility. Brines containing iron in the reduced state are often obtained from aquifers for use in polymer hydration. These brines are shown to be prone to causing immediate degradation if exposed to air during or after polymer hydration because of the oxidation of soluble iron. If this cannot be avoided, preaeration may be a feasible strategy to minimize degradation during hydration. However, care must be taken to ensure subsequent degradation is not caused by the injection of a polymer solution containing oxygen into a formation containing iron. For instance, sodium dithionite can be added downstream of the last exposure to oxygen. The use of sodium carbonate may also mitigate degradation caused by the oxidation of iron (II) during polymer hydration.

Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.

Oxidative degradation of polymers is a serious concern in the field application of enhanced oil recovery polymers. This study is an attempt to resolve some of the discrepancies in the literature regarding the occurance and extent of this degradation, as well as to present a coherent framework for discussing the multitude of possible radical reactions. Sodium carbonate and bicarbonate are demonstrated to play a key role in stabilizing polymer against multiple reported sources of degradation, and it seems likely that this is due to their effect on iron solubility. Brines containing iron in the reduced state are often obtained from aquifers for use in polymer hydration. These brines are shown to be prone to causing immediate degradation if exposed to air during or after polymer hydration due to the oxidation of the iron. If this cannot be avoided, preaeration may be a feasible strategy to minimize degradation during hydration. However, care must be taken to ensure subsequent degradation is not caused by the injection of a polymer solution containing oxygen into a formation containing iron. For instance, sodium dithionite can be added downstream of the last exposure to oxygen. The use of sodium carbonate may also mitigate degradation due to the oxidation of iron (II) during polymer hydration.

Large hydrophobe Carboxylate surfactants (MW above 1000) are a relatively new class of surfactants developed for surfactant flooding during chemical enhanced oil recovery (EOR) processes. The presence of carboxylate groups and alkoxylate groups in the molecules provides stability and salinity tolerance at high temperature and in high salinity environments. Many high temperature reservoirs have injection and reservoir brine containing high concentrations of divalent ions making them prime targets for using carboxylate surfactants. Much of the earlier literature showed successful carboxylate applications at high pH during alkali-enhanced flooding, as the high pH stabilizes the carboxylate groups. Such processes are not feasible in the presence of hardness at high temperatures. We present an approach where we use an alkali buffer wherein the pH is adjusted from highly basic to near neutral. Under such conditions we demonstrated low retention and high performance in terms of phase behavior and coreflood oil recovery.

Results from two field trials designated as Minas Surfactant Field Trial 2 (SFT2) and Polymer Field Trial (PFT) are presented. Quantitative tracer interpretations were used to estimate sweep and displacement efficiency and confirm the performance of both SFT2 and PFT. The pilot patterns in both SFT2 and PFT consisted of a central producer surrounded by six chemical injectors and further confined by six hydraulic control wells that injected water alone. In order to make quantitative comparisons, both the surfactant-polymer and polymer pilots were run at the same mobility ratios to understand if incremental recovery was a function of improved volumetric sweep or increased displacement sweep efficiency. The results of the two pilots show that at the same well spacing and mobility ratio, incremental sweep is very similar and significantly higher than pre-chemical waterfloods. An important finding of the tracer tests is that water injectors should not be used to confine chemical injectors as the water tends to bypass the higher viscosity polymer chase and potentially disrupts the oil-bank. The results from the pilots indicate that for a mature, waterflooded reservoir, surfactant-polymer flooding was preferable as it lowered the final remaining oil saturation and increased oil recovery. Polymer flooding mainly accelerated oil recovery by recovering additional oil from unswept zones and had minimal impact in a mature reservoir. Interwell tracer technology combined with moment analyses were used to make quantitative comparisons of both processes and allowed for several technical insights. This is the first time in literature that a quantitative comparison of surfactant-polymer flooding and polymer flooding alone has been presented.