Smart water flooding performance in carbonate reservoirs: an experimental approach for tertiary oil recovery

Abstract

Smart water flooding as a developing technique utilizes modified water chemistry in terms of salinity and composition to prepare the best-suited brine composition for a specific brine/oil/rock system to obtain higher oil recovery efficiency. Huge amount of unrecovered oil is expected to be remained in carbonate reservoirs; however, few research works on incremental oil recovery during smart water injection in carbonate cores at reservoir condition are reported. Several core flooding tests using one of the Iranian carbonate reservoir rock are conducted to check the effectiveness of smart water injection for more oil recovery efficiency. The results reaffirm the positive effect of sulfate ions to play a key role for better smart water performance. Moreover, it was concluded that the calcium ion concentration is not as effective as magnesium ion for the tests performed at reservoir condition. Synthetic sea water (high-salinity) flooding was considered as the base scenario which results in almost 63% oil recovery efficiency for secondary recovery scenario. Formation of micro-emulsions was found to be the main reason of additional pressure drop during low-salinity water flooding. This clearly showed that the diluted smart water injecting increases the ultimate oil recovery up to 4-12% for already water-flooded carbonate reservoirs.

An investigation into the roles of chlorides and sulphate salts on the performance of low-salinity injection in sandstone reservoirs: experimental approach

“…So, the better recovery here is attributed to other displacement mechanisms. Furthermore, 5000 ppm Cl brine produced significant oil recovery compared to the distilled water as opposed to the assumption that Na + and Cl − and other monovalent do not have any wettability altering properties (Darvish Sarvestani et al 2019).…”

“…This is indicative of the fact that in the SO 4 runs, the fluids (brine and oil) moved as a single or near homogenous unit compared to the other two runs, with distilled water having the most unstable fluctuations and spiking. The much smoother flow of the SO 4 can be explained by either the salting-in effect mechanism (Rezaeidoust et al 2009) or the emulsification of the oil and brines (Darvish Sarvestani et al 2019) during the displacement which are all defined by the IFT between the two fluids. Upon physical inspection of the effluents, the oil in water emulsion showed larger oil droplets in the brine and distinct layer between their interface in Cl-based brines.…”

“…They varied the sodium chloride (NaCl) concentration with the sulphates and attributed the improved recovery to changing the wettability of the core sample to a more water wet state, the pH increase and the decrease in NaCl salts. It is common knowledge that NaCl is considered nonactive in terms of LSF (Darvish Sarvestani et al 2019). This has been shown to be as a result of the monovalent sodium ion (Na + ), in that, it does not have any wettability altering properties in the presence of other divalent cations like Mg 2+ .…”

“…This has been shown to be as a result of the monovalent sodium ion (Na + ), in that, it does not have any wettability altering properties in the presence of other divalent cations like Mg 2+ . But Darvish Sarvestani et al (2019) stated that KCl, a monovalent salt, can change the rock wettability to more water wet and improved oil recovery can be realised. Suman et al 2014, however, used NaCl brines for core flooding experiments and realised increased recovery of oil by reducing the concentrations.…”

Optical measurements of oil release from calcite packed beds in microfluidic channels

“…The waterflooding conditions explored using two microfluidic chips (with the same design) are summarized in Table 1. In IOR from oil fields, the typical injection velocity typically varies between 1 and 4 ft/day; some variations exist between literature values (Gerold et al 2018;Sarvestani et al 2019). Since the flow rates correspond to typical capillary numbers in the range 10 -6 to 10 -5 , (Guo et al 2015) we have also explored this range (Table 1).…”