Page 80 - Hybrid Enhanced Oil Recovery Using Smart Waterflooding

72 Hybrid Enhanced Oil Recovery using Smart Waterflooding 0.5

Differential Pressure (mbar) 4000 Reversing the core 0.4 Injection Rate (ml/min)
5000
4500

3500
0.3
3000
injection face
2500
2000
0.2
1500
1000
500
0
0 0.1
0 3 6 9 12 15
Pore Volumes Injected (PVinj)
R4: Berea - 300 ppm high salinity polymer solution
R3: Berea - 300 ppm high salinity LPS solution
R4: Injection Rate
R3: Injection Rate
FIG. 4.5 The comparison of conventional polymer flood and linked polymer flood in high salinity condition.
(Credit: From Shiran, B. S., & Skauge, A. (2014). Similarities and differences of low salinity polymer and low
salinity LPS (linked polymer solutions) for enhanced oil recovery. Journal of Dispersion Science and
Technology, 35(12), 1656e1664. https://doi.org/10.1080/01932691.2013.879532.)

solution using Flopaam 3630s and aluminum citrate as treatment using synthetic seawater in high saline condi-
cross-linker. The polymer of 300 ppm is used for both tion (Fig. 4.5). It is observed that the differential pres-
LSPF and gel treatment. sure of polymer flood increases by the significant
The study conducted the coreflooding of single- adsorption of polymer until the adsorption of polymer
phase and two-phase displacements. Firstly, the reaches to the maximum adsorption level. For the
displacement experiments of the single phase are car- experimental results of gel treatment, continuously
ried out to compare the propagation of polymer and increasing differential pressure is observed. It is under-
linked polymer solution at different salinity conditions. stood that the excess amount of divalent cations bridges
The change of differential pressure corresponding to the the negatively charged polymer molecules and results in
injection rate is measured to quantify the transport of the more aggregation of linked polymer. The size of ag-
polymer and linked polymer in the porous media. In gregation in high salinity condition becomes larger than
the single-phase experiments using the low-permeable pore throat and introduces the higher mechanical
Berea sandstone, the residual resistance factors between entrapment. In comparison with the results of high
LSPF and low salinityeaugmented gel treatment are salinity conditions, the adsorption of polymer on to
compared. The higher residual resistance factor with the rock surface and the arrogation of linked polymer
7% is observed in low salinityeaugmented gel treat- can be reduced in the low salinity condition. The prop-
ment than the LSPF. However, the difference is accept- agations of polymer and linked polymer become to be
able considering the initial permeability difference. It similar in the low salinity condition. The second exper-
indicates that the propagation behavior between gel iments of two-phase displacement investigate the
treatment and polymer flood is approximately similar change of residual oil saturation of LSPF and low
in the low saline, low permeable, and intermediate salinityeaugmented gel treatment following secondary
water-wet conditions. For the high-permeable LSWF. It is observed that the reduction of residual oil
Bentheimer cores, both the low salinityeaugmented saturation up to 48.8% and 12.9% by LSPF and low
gel treatment and LSPF processes show the identical his- salinityeaugmented gel treatment, respectively, in the
tory of differential pressure with injection rate. These intermediate water-wet cores, but negligible change in
observations also confirm the comparable transport of the fully water-wet cores. Although these observations
both polymer and linked polymer in low saline, high show the higher performance of LSPF without cross-
permeable, and intermediate water-wet conditions. linker than that with cross-linker in one-dimensional
Additional single-phase experiments monitor the differ- and homogeneous system, the heterogeneity of system
ential pressure of conventional polymer flood and gel can provide different results.