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.