Flooding Performance analysis and Decision Criteria
CMG-STARS is useful in modelling the surfactant/polymer/nanoparticle flooding experiment, with good agreement between the experimental and simulated data [17,37,65,68]. Figs. 13(a), 13(b) and 13(c) show the oil saturation, water cut and recovery factor profiles for different chemical fluid compositions respectively. A Cartesian model was developed with constant injection rate and constant pressure condition to investigate the EOR performance of analyzed fluids. Oil saturation curves showed that surfactant-polymer-nanoparticle aqueous fluids are capable of extracting maximum amount of trapped crude oil in comparison to other analyzed systems. The residual oil saturation (sor) values for cases I, II and III were found to be 31.96%, 30.68% and 29.30% respectively at the end of simulation tests. Crude oil was recovered during secondary flooding experiments, until water cut reaches ≥ 95%. At this stage, tertiary fluids were introduced to improve oil production and reduce water cut percentages. All three flooding instances discussed herein showed similar behavior in terms of water cut versus pore volume plots. In fact, oil displacement experiment was stopped when the quantity of produced oil was extremely low from economical aspect. EOR investigations achieved crude oil recoveries of 15.06% during {14-6-14 GS + chase water} flooding, 17.42% during {14-6-14 GS + PHPA + chase water} flooding, and 18.49% during {14-6-14 GS + PHPA + SiO2 + chase water} flooding. Surfactant-polymer-nanoparticle (SPN) flooding recovered an additional ~1.07% of OOIP over surfactant-polymer flooding; and 3.43% over conventional surfactant flooding process. The simulated results were successfully matched with experimental flooding data. This may not seem very significant in terms of percentages. However, if the field-scale data is assumed, additional barrels of crude oil can be produced. This translates to improved efficacy of surfactant-polymer-nanoparticle based EOR method.
Fig. 13. Flooding performance versus injected pore volume (PV) of different aqueous EOR fluids, expressed in terms of (a) oil saturation; (b) water cut; and (c) recovery factor.
Conclusions
Laboratory core-flood experiments were simulated using CMG-STARS to investigate the flooding performance of {14-6-14 GS +/ PHPA polymer +/ SiO2 nanoparticle} aqueous fluids. Aqueous chemical systems exhibited ultra-low IFT, rock-wetting behavior and pseudoplastic flow character, as evident from experimental analyses. Surfactant fluids were characterized by micelles/aggregates in bulk phase, which altered to network structure of dispersed micelles interconnected by entangled polymer chains in surfactant-polymer solutions. This structural attribute becomes more pronounced in the surfactant-polymer-nanoparticle (SPN) fluids, resulting in the formation of supra-molecular network structure with enhanced oil-attracting properties. Cartesian single-porosity model was employed to develop a robust numerical approach to match flooding properties of analyzed fluids. Initially, water-flood was simulated for 208 min. After secondary oil recovery, tertiary chemicals were injected to improve oil production and maintain pressure drop within reservoir pore-throats. This flooding process involved chemical injection period of 86 min, and ~150 min chase-water flooding period. Oil saturation maps showed that oil saturation within core sample decreased to 31.96%, 30.68% and 29.30% of original liquid content at the end of flooding studies, involving {14-6-14 GS}, {14-6-14 GS + PHPA} and {14-6-14 GS + PHPA + SiO2} fluids respectively. Relative permeability curves were adjusted to model flooding results, and proved to be useful in predicting oil displacement results. Tertiary flooding simulations revealed EOR percentages of 15.06%, 17.42% and 18.49% of original oil in place (OOIP) in the presence of {14-6-14 GS + chase water}, {14-6-14 GS + PHPA + chase water} and {14-6-14 GS + PHPA + SiO2 + chase water} respectively. In summary, the analyzed aqueous fluids exhibit favorable recoveries and economic feasibility for EOR in sandstone rock systems.