UC Berkeley

Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil
production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some adhered crude oil.
Composition design of the modified brine to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone,
which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity
hinders rational design of the tailored brine to improve oil recovery.
Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion
exchange, and dispersion (Yutkin et. al 2021). Here we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium
carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at
injection rates higher than 1000 ft/day. Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long
concentration history tails.
Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in
high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.