Investigation of Smart Waterflooding in Sandstone Reservoirs: Experimental and Simulation Study Part 2
- Hasan N. Al-Saedi (Missouri University of Science and Technology) | Ralph E. Flori (Missouri University of Science and Technology) | Mortadha Alsaba (Australian College of Kuwait)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- February 2020
- Document Type
- Journal Paper
- 2020.Society of Petroleum Engineers
- smartwater, enhanced oil recovery, heavy oil, low salinity waterflooding, reactive transport modeling
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- 72 since 2007
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In a previous work (Al-Saedi et al. 2018c), we studied the effect of mineral composition of cores (using synthetic columns with varying mineralogy) on low-salinity (LS) waterflooding, and we presented a reactive-transport model (RTM) for the water/rock interactions. The results showed that kaolinite has the strongest effect and then quartz because of the high kaolinite surface area, and the most effective complexes were >SiOH (hydroxylated Si), >AlO– (aluminum oxide complex on quartz surface), and >SiO– (silicon mono oxide complex on quartz surface).
In this paper, we use the same Bartlesville Sandstone cores (constant mineralogy) for all cases to investigate the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation using CrunchFlow (Steefel 2009) were conducted to better understand smart waterflooding.
Bartlesville Sandstone cores were saturated with heavy oil and connate formation water. Secondary waterflooding of these cores with formation water (FW) at 25°C resulted in an ultimate oil recovery of approximately 50% original oil in place (OOIP) for all reservoir cores in this study. FW salinity was 104,550 ppm. FW was diluted twice to obtain Smart Water 1 (SMW1). SMW2 was similar to SMW1 but depleted in divalent cations (Ca2+ and Mg2+). SMW3 was also similar to SMW1 but depleted in Mg2þ and SO2–4 , whereas SMW4 was the same as SMW1 but Ca2+ was diluted 100 times. Seawater (SW) salinity was 48,300 ppm, which is close to the SMW salinity (52,275 ppm). No oil recovery was observed during SMW1 flooding, whereas softening SMW1 (SMW2) resulted in a significant additional oil recovery of OOIP. Depleting Mg2+ and SO2–4 resulted in additional oil recovery but less than in SMW2. Diluting Ca2+ 100 times was the second-best scenario, after depleted Ca2+ in SMW2. The results of this study showed that the more diluted Ca2+ is in the injected brine, the more additional oil recovery that can be obtained, although the other divalent/monovalent cations/anions were increased or decreased or even depleted.
Additional reservoir cores were allocated for surface-reactivity tests. The absence of an oil phase allows us to isolate the important water/rock reactions. The Ca2+, Mg2+, and SO2–4 effluents for all cores were matched using CrunchFlow, and then further investigations of the water/rock interactions were conducted. The RTM showed that decreasing the Mg2þ concentration will decrease the number of the most effective kaolinite edges Si-O– and Al-O–, but was not as pronounced as that in the presence of Ca2+, which explains why lowering the Mg2+ concentration gives lower additional oil recovery and why lowering the Ca2þ concentration gives higher additional oil recovery.
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