Chemical EOR flooding using hydrolyzed polyacrylamide (HPAM) is considered nowadays a state-of-the-art tertiary recovery process and has been conventionally applied on a full-field scale worldwide. The addition of these standard polymers improves the mobility of the injected fluid and thus maximize sweep; however, application is only limited to mild reservoir temperatures and low brine salinity ranges. Therefore, a more thermally stable and more resistant "associative polymers" were derived, by incorporating specific hydrophobic groups into the HPAM polymer backbone, to offer performance advantages with regards to viscosifying efficiency and salt tolerance when compared to the standard HPAM. However, only a handful of field cases were reported in the literature. Thus, this paper will present the unique application of this associative polymer technology in a field pilot for one of the major E&P companies and discusses the corresponding lab evaluations leading up to the field trial.

To confirm the advantages of using associative polymer over of standard HPAM, rheology and filterability measurements were conducted. Moreover, linear coreflood experiments in presence of oil have been performed at target field conditions (low temperature and higher salinity) with various polymer concentrations. The resistance factors measured in the coreflood experiments indicated that 750 and 1,250 ppm of associative polymer and HPAM, respectively, are adequate to deliver the required mobility ratio of 1 and accordingly the oil recovery can be similar for the two different polymers at these concentrations. Moreover, dynamic adsorption measurements conducted at the same polymer concentration reveal a smooth propagation of the associative polymer through the porous medium. Based on these findings, it is concluded that the associative polymer offers a significant performance advantage over the HPAM due to the lower polymer dose required to achieve the target performance.

After successful lab evaluations and in preparation for a multi-well pilot, a field injectivity trial was planned accordingly to test the propagation of the synthesized polymer in the reservoir. Subsequently, the selected associative polymer was successfully injected into the reservoir over a period of two months in two injectors at a steady injection rate of 50 and 300 m3/d. The measured well head pressures of the two injection wells was stable for the entire test duration, indicating a good polymer injectivity with no observed formation plugging.

This newly developed associative polymer was proposed to the field's operator as a promising alternative solution to unlock additional reserves increase oil recovery and a full-field polymer flood expansion is planned next. To our knowledge, this is one of the few reported field trials with associative polymers and should facilitate field implementation of this technology.

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