Page 93 - Hybrid Enhanced Oil Recovery Using Smart Waterflooding

CHAPTER 4 Hybrid Chemical EOR Using Low-Salinity and Smart Waterflood 85

saline chasing water injection. In the analysis of fracture In the first set of coreflooding, 10-times-diluted and
width, microgel with 0.01% NaCl brine shows the less 100-times-diluted seawater injections recover addi-
incremental oil recovery as chasing water has low tional 8% and 2% oil, respectively, because of wetta-
salinity. The residual resistance factor shows the equiv- bility modification effect. The second set also shows
alent trend. The effect of wettability on the performance that sulfate-enriched seawaters by factors of 2 and 3 pro-
of low salinityebased microgel is investigated. The duce more oil recovery by 13% and 6.5%, respectively,
microgel injection with low-salinity water and chasing which are attributed to the wettability modification.
water is effective to increase oil recovery on both water- The following three displacement tests investigate the
and oil-wet reservoirs. Overall, the oil production is oil recovery from fully and partially open-fractured
higher in water-wet than oil-wet cores. Additional cores. Each displacement test includes a number of cor-
displacement experiment using water-wet core, in eflooding. The coreflooding is designed as the gel treat-
which the wettability modification by LSWF is ineffec- ment following the preflush of seawater injection,
tive, confirms the role of low salinity on the gel postflush of seawater, and chasing water of low-
swelling. The preinjection of 0.01% NaCl and 1% salinity water or modified seawater injections. In the
NaCl brines provides negligible difference in the oil re- test with fully fractured core, the first coreflooding eval-
covery, which implies the negligible wettability modifi- uates the hybrid gel treatment with LSWF (Fig. 4.17A).
cation. The PPG and postflush injection using 0.01% The injection of microgel requires significant injection
NaCl brine show slightly higher recovery of 2% than pressure. The postflush of seawater after the gel treat-
the injection using 1% NaCl brine. The incremental ment produces 31% of oil recovery. The chasing water
oil recovery is completely attributed to the higher of 10-times-diluted seawater enhances the oil recovery
swelling ratio of microgel in the low-salinity water con- by 13%, and the successive chasing water of 100-
dition. Lastly, because the higher placing pressure of times-diluted seawater increases the oil recovery by
PPG injects higher volume of microgel, the oil recovery 26%. Albeit the chasing water using diluted seawater
factor and residual resistance factor increase with produces some microgel particles, pressure drop is still
reducing fracture conductivity. This study demonstrated high. The microgel particle production is the result of
the effects of low-salinity water injection on the micro- the weak gel formation in the low salinity condition.
gel swelling and wettability modification and effects of The high injection pressure corresponds to the results
fracture width and placing pressure of PPG on the per- of previous swelling ratio measurements, higher
formance of hybrid low salinityebased gel treatment. swelling ratio of microgel in low salinity condition.
Alhuraishawy, Bai, and Wei (2018) published the Considering the pressure drop, the increasing oil recov-
comprehensive experiments of the hybrid process of ery is attributed to both the wettability modification
varying the salinity and potential-determining ion con- and enhanced gel-blocking capacity by the hybrid pro-
centration. In the study, the common brines of forma- cess. A couple of corefloodings analyze the performance
tion water and seawater are prepared. The formation of the sulfate-enriched seawater injections after gel treat-
water has higher salinity than seawater by a factor of ment (Fig. 4.17B). It is consistently drawn that the
about 3. To evaluate the effect of sulfate ion, which is higher oil recovery is also observed with an increase
the potential-determining ion in the mechanism of in the sulfate concentration of seawater. When the gel
LSWF, and salinity on the performance of the hybrid particle production is not observed, chasing water injec-
process, two-times and three-times sulfate-enriched sea- tion of modified seawater results in the equivalent pres-
waters and the diluted seawaters by factors of 10 and sure drop compared with the postflush of seawater. This
100 are manufactured. Before the displacement experi- result indicates the negligible improvement in gel-
ment, swelling ratio of microgel is measured for varying blocking capacity as well as gel strength during the in-
brines. All seawater and sulfate-enriched seawaters lead jection of sulfate-enriched seawater. It is in line with
to the gel swelling ratio of 32, and the low-salinity wa- the observation of swelling ratio measurement. Both
ters of 10-times- and 100-times-diluted seawaters result seawater and sulfate-enriched seawater have same de-
in the swelling ratios of 120 and 180, respectively. In gree of swelling ratio. Other displacement tests also
the displacement experiment, the first test evaluates observe similar results. Based on these displacement
the effects of low salinity and sulfate ions on the oil re- tests, a couple of conclusions are drawn. The gel-
covery from nonfractured carbonate cores. In the test, blocking capacity can be secured in sulfate-enriched
the two sets of coreflooding are designed with second- seawater and enhanced in low-salinity water. In addi-
ary injection of seawater and tertiary injection of low- tion, the chasing water injection of low-salinity/
salinity water or sulfate-enriched seawater, respectively. modified seawater introduces wettability modification.