Low Salinity Surfactant Flooding: Role of Surfactant and Salt

Kakati, Abhijit; Sangwai, Jitendra S.

doi:10.1007/978-3-030-70026-3_8

Cited by 1 publication

(2 citation statements)

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“…Such microemulsion profile is not the desired profile as it results in a lower reduction of S or . Moreover, the dilution and adsorption of surfactant inside the porous media can cause the microemulsion type to transition to Type I, resulting in higher partitioning of surfactant into the aqueous phase and causing excessive surfactant loss due to early breakthrough [80].…”

Section: Coreflood 1 (Cf-1)mentioning

confidence: 99%

“…However, the gradual negative salinity gradient profile shows the best performance in terms of the remaining oil in the core (ROIC), compared to the EWSF case and the sharper negative salinity gradient case. The reason for higher recovery of residual oil in case of a gradual negative salinity gradient is the reduced surfactant loss during IWS-1 and IWS-2 flooding stages, development of Winsor Type III microemulsion during IWS-3 injection stage for a longer duration providing ultra-low IFT between oil and water, and redistribution of surfactant between aqueous an oleic phases as phase behavior transitions from Type-III to Type-I during IWS-3 [80,82,83]. The results of this study can be validated and supported by similar studies in the literature.…”

Section: Coreflood-3 (Cf-3)mentioning

confidence: 99%

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Optimization of Low Salinity Water/Surfactant Flooding Design for Oil-Wet Carbonate Reservoirs by Introducing a Negative Salinity Gradient

et al. 2022

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Engineered water surfactant flooding (EWSF) is a novel EOR technique to reduce residual oil saturation; however, it becomes quite challenging to obtain Winsor Type III microemulsion and the lowest IFT under actual reservoir conditions if only low salinity water is used. The main objective of this study was to design a negative salinity gradient to optimize the performance of the hybrid method. Three corefloods were performed on carbonate outcrop samples. The injection sequence in the first test was conventional waterflooding followed by optimum engineered water injection (2900 ppm) and finally an EWSF stage. The second and third tests were conducted using a varying negative salinity gradient. Engineered water for this study was designed by 10 times dilution of Caspian Sea water and spiking with key active ions. A higher salinity gradient was used for the first negative salinity gradient test. A total of 4300 ppm brine with 1 wt% surfactant was injected as a pre-flush after waterflooding followed by a further reduced salinity brine (~1400 ppm). The second negative salinity gradient test consisted of three post-waterflooding injection stages with salinities of 4600, 3700, and 290 ppm, respectively. Up to 8% and 16% more incremental oil recovery after waterflooding was obtained in the second and third tests, respectively, as compared to the first test. The descending order of brine salinity helped to create an optimum salinity environment for the surfactant despite surfactant adsorption. This study provided an optimum design for a successful LSSF test by adjusting the brine salinity and creating a negative salinity gradient during surfactant flooding. A higher reduction in residual oil saturation can be achieved by carefully designing an LSSF test, improving project economics.

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Section: Coreflood 1 (Cf-1)mentioning

confidence: 99%

Section: Coreflood-3 (Cf-3)mentioning

confidence: 99%