Adoption of phase behavior tests and negative salinity gradient concept to optimize Daqing oilfield alkaline-surfactant-polymer flooding. (15th November 2018)

• Record Type: Journal Article
• Authors: Chen, Zhao; Han, Xu; Kurnia, Ivan; Yu, Jianjia; Zhang, Guoyin; Li, Liang
• Is Part Of: Fuel. Volume 232(2018)
• Page Start: 71
• Page End: 80
• Publication Date: 2018-11-15
• Subjects: Phase behavior -- Negative salinity gradient -- Alkaline-surfactant-polymer flooding -- Solubility -- Interfacial tension -- Improved oil recovery; Fuel -- Periodicals; Coal -- Periodicals; Coal; Fuel; Periodicals; 662.6
• DOI: 10.1016/j.fuel.2018.05.130
• Languages: English
• ISSNs: 0016-2361

Abstract

Abstract: A high performance surfactant formulation was developed using more universally accepted Winsor type phase behavior tests rather than relying primarily on interfacial tension (IFT) measurement for the first time for Daqing oilfield. A surfactant mixture of alkylbenzene sulfonate and fatty alcohol propoxylated ether sulfate was identified which was able to form middle-phase microemulsion with Daqing less reactive crude oil (acid number below 0.1 mg KOH/g crude), lower oil water IFT to ultralow level, and hold desired aqueous stability. Winsor type phase behavior tests at various water oil ratios (WORs) showed the optimum salinity changed slightly from 1.95% to 2% when WOR was increased from 5:5 to 9:1 due to the low reactivity of the Daqing crude oil. To investigate the significance of salinity on Daqing alkaline-surfactant-polymer (ASP) flooding, 4 salinity profiles were designed during coreflooding that corresponded to different types of microemulsions including III–III–I, I–III–I, II–III–I, and III–III–III. For each coreflooding, 0.3 pore volume (PV) of ASP slug with 0.3% total surfactant concentration and 0.2 PV polymer drive was injected. The results demonstrated when negative salinity gradient (3.0%–2.0%–0.5% Na2 CO3 in waterflood, ASP, and polymer slugs) was applied, the highest incremental oil recovery of 45.9% original oil in place (OOIP) was achieved. If no Na2 CO3 was added in water preflush prior to the injection of ASP slug, the lowest incremental recovery of 32.8% OOIP was observed. For a constant salinity profile at optimum salinity, an intermediate oil recovery (37.4%) was encountered. The measurement of surfactant and Na2 CO3 concentrations in the effluents indicated that when negative salinity gradient (II–III–I) was applied, the surfactant loss in the porous media and the oil phase was moderate compared to the two corefloods with III–III–III (highest surfactant loss) emulsion and I–III–I emulsion (lowest surfactant loss). This implied that at optimized salinity profile, the surfactants were more close to hydrophobic-hydrophilic balance during the propagation in the reservoir, which showed the highest potential of increasing oil recovery for the Daqing Oilfield without significantly increasing chemical consumption.