Abstract:Wettability of an
oil/brine/rock system is a critical petrophysical
parameter, which governs subsurface multiphase flow behavior, thus
hydrocarbon recovery. While the mechanisms of CO2-assisted
enhanced oil recovery (EOR) techniques have been extensively investigated
in carbonate reservoirs, few have been done to identify the controlling
factor of CO2-induced wettability alteration, and fewer
have looked beyond the implications for CO2-assisted EOR.
We thus hypothesize that CO2-assisted EOR techniques cause
a … Show more
“…This is because non-carbonated brine gives a strongly negative surface potential, whereas the surface potential of brine-calcite remains positive, triggering attractive forces. We believe that both electrostatic and nonelectrostatic physisorption together with competitive ion chemisorption (ion exchange and surface complexation modelling) 38 would be combined to better account for the total disjoining pressure. Figure 9 Total disjoing pressure under the condition of constant charge (solid lines) and constant potential (dotted lines) versus film thickness in the presence of carbonated and non-carbonated brines with different ion type and salinity.…”
Injecting CO2 into oil reservoirs appears to be cost-effective and environmentally friendly due to decreasing the use of chemicals and cutting back on the greenhouse gas emission released. However, there is a pressing need for new algorithms to characterize oil/brine/rock system wettability, thus better predict and manage CO2 geological storage and enhanced oil recovery in oil reservoirs. We coupled surface complexation/CO2 and calcite dissolution model, and accurately predicted measured oil-on-calcite contact angles in NaCl and CaCl2 solutions with and without CO2. Contact angles decreased in carbonated water indicating increased hydrophilicity under carbonation. Lowered salinity increased hydrophilicity as did Ca2+. Hydrophilicity correlates with independently calculated oil-calcite electrostatic bridging. The link between the two may be used to better implement CO2 EOR in fields.
“…This is because non-carbonated brine gives a strongly negative surface potential, whereas the surface potential of brine-calcite remains positive, triggering attractive forces. We believe that both electrostatic and nonelectrostatic physisorption together with competitive ion chemisorption (ion exchange and surface complexation modelling) 38 would be combined to better account for the total disjoining pressure. Figure 9 Total disjoing pressure under the condition of constant charge (solid lines) and constant potential (dotted lines) versus film thickness in the presence of carbonated and non-carbonated brines with different ion type and salinity.…”
Injecting CO2 into oil reservoirs appears to be cost-effective and environmentally friendly due to decreasing the use of chemicals and cutting back on the greenhouse gas emission released. However, there is a pressing need for new algorithms to characterize oil/brine/rock system wettability, thus better predict and manage CO2 geological storage and enhanced oil recovery in oil reservoirs. We coupled surface complexation/CO2 and calcite dissolution model, and accurately predicted measured oil-on-calcite contact angles in NaCl and CaCl2 solutions with and without CO2. Contact angles decreased in carbonated water indicating increased hydrophilicity under carbonation. Lowered salinity increased hydrophilicity as did Ca2+. Hydrophilicity correlates with independently calculated oil-calcite electrostatic bridging. The link between the two may be used to better implement CO2 EOR in fields.
“…While wettability alternation is considered as the main mechanism behind LSE, the understanding of which factors control the wettability variation is incomplete due to the complexity of the interactions occurring in the oil/brine/rock system. The two approaches that reveal the controlling factors behind the wettability alteration are (a) double-layer expansion between fine particles and limited fines release (LFR) between oil/rock contact areas (Nasralla and Nasr-El-Din 2014;Tang and Morrow 1999a;Xie et al 2016) and (b) surface complexation modeling (Brady and Krumhansl 2012;Brady and Thyne 2016;Brady et al 2015;Mahani et al 2017;Xie et al 2017).…”
Nanofluids and low-salinity water (LSW) flooding are two novel techniques for enhanced oil recovery. Despite some efforts on investigating benefits of each method, the pros and cons of their combined application need to be evaluated. This work sheds light on performance of LSW augmented with nanoparticles through examining wettability alteration and the amount of incremental oil recovery during the displacement process. To this end, nanofluids were prepared by dispersing silica nanoparticles (0.1 wt%, 0.25 wt%, 0.5 wt% and 0.75 wt%) in 2, 10, 20 and 100 times diluted samples of Persian Gulf seawater. Contact angle measurements revealed a crucial role of temperature, where no wettability alteration occurred up to 80 °C. Also, an optimum wettability state (with contact angle 22°) was detected with a 20 times diluted sample of seawater augmented with 0.25 wt% silica nanoparticles. Also, extreme dilution (herein 100 times) will be of no significance. Throughout micromodel flooding, it was found that in an oil-wet condition, a combination of silica nanoparticles dispersed in 20 times diluted brine had the highest displacement efficiency compared to silica nanofluids prepared with deionized water. Finally, by comparing oil recoveries in both water-and oil-wet micromodels, it was concluded that nanoparticles could enhance applicability of LSW via strengthening wettability alteration toward a favorable state and improving the sweep efficiency.
“…This is mostly because elevating the pH of the brine causes deprotonation of the carboxylic functional group according to the reaction R−COOH = R−COO − + H + , which is well supported by published literature. 38,41,81 For instance, Brady et al 81 conducted geochemical modeling to investigate the impact of pH variation on the oil surface species. They found that raising the pH of sodium chloride brine from 4 to 9 causes an increase in the density of −COO − in the oil surface from 4 to 6 μmol/m 2 , suggesting that at high pH values the oil surface charge would be predominated by the −COO − oil group.…”
Wettability alteration seems to be the main physicochemical process during low salinity water injection in carbonate formations. A pH increase due to calcite dissolution during low salinity water injection may affect oil−brine−rock interaction and thereby wettability. However, far too little attention has been paid to quantifying the impact of such an pH increase on acidic oil− carbonate adhesion. Therefore, we measured contact angles between acidic oil (−COOH) and calcite crystal in the presence of 10 000 ppm NaCl solutions at different pHs (6.5, 9.5 and 11) at ambient conditions. Furthermore, we used atomic force microscopy (AFM) to measure the adhesion force between acidic oil groups (−COOH) and calcite substrate at different pHs (9.5 and 11) at similar conditions of the contact angle experiments. Moreover, to confirm the contact angle and AFM results, we measured the zeta potential of acidic oil−brine and calcite−brine interfaces at the same condition and calculated the thermodynamic isotherm disjoining pressure. Our results show that the contact angle reduces from 134 to 95°as the pH increases from 6.5 to 11, increasing hydrophilicity. Adhesion force measurements show that increasing pH reduces the adhesion force between the acidic oil and carbonate in line with contact angle results. Zeta potential results show that increasing the pH increases the negativity of the zeta potential of acidic oil−brine and calcite−brine interfaces, implying the increase of the electrical double layer force. Furthermore, the total disjoining pressure isotherm becomes less negative with increasing pH, implying an increase of hydrophilicity. Taken together, our results confirm that a local pH increase due to calcite dissolution during low salinity water injection would prevail in the wettability alteration process in particular for high acidic oil bearing carbonate reservoirs.
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