Modeling Low-Salinity Waterflooding in Chalk and Limestone Reservoirs

Abstract

The injection of low-salinity brines can improve oil recovery in carbonate reservoirs by changing the rock wettability from being more oil-wet to being more water-wet. Existing models use an empirical dependence of wettability based on variables including equivalent salinity and ionic strength. We recently developed a process-based model that mechanistically includes the geochemical interactions between crude oil, brine, and the chalk surface that alter rock wettability. In this research, we extend the previous model by including mineral dissolution reactions, therefore enabling the modeling of low-salinity flooding in chalks and limestone cores with and without anhydrite, which is considered to be a key factor in controlling the extent of improved oil recovery (IOR). We examine the role of mineralogy by including surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite in the extended model. These reactions, coupled with the equations of multiphase flow and transport, are solved simultaneously using an in-house simulator, PennSim. Relative permeability functions and residual oil saturation during flooding are adjusted dynamically according to the concentration of oil acids attached to the mineral surface. Core flooding experiments from the Stevns Klint (SK) chalk and a Middle Eastern carbonate with a small volume fraction of anhydrite are used to tune the reaction network and predict recovery. Simulation results agree with the observed effluent concentrations of SO4 2–, Ca2+, and Mg2+ reported from chromatographic wettability tests and the measured recoveries under differing compositions in chalk and limestone cores. For the SK chalk without anhydrite, lower Na+ and Cl– concentrations under constant SO4 2– conditions leads to IOR by as much as 6% OOIP. Lower salinity alone, however, does not lead to IOR in limestones without anhydrite. Instead, anhydrite dissolution provides a natural source of sulfate and increases oil recovery by 5% when injecting diluted formation water. Simulations of two-dimensional (2D) five-spot patterns using tuned reaction networks demonstrated that IORs from 5% to 20% OOIP can be obtained after two pore volumes are injected. These IORs are greatly dependent on the aqueous chemistry of the injected fluid and sweep. The results highlight the critical importance of understanding the mineralogy and including a mechanistic reaction model in the simulation of low-salinity water floods.

Low salinity effect on the recovery of oil trapped by nanopores: A molecular dynamics study

“…The wettability change has been confirmed by various experiments including chromatographic wettability tests, contact angle measurements, spontaneous imbibition tests, core flooding, etc [7]. Apart from these experimental works, the wettability alteration process has been modeled and captured by using empirical relations between wettability and salt solution parameters [8], taking into account surface reactions mechanistically [7], and focusing on the kinetics of oil detachments from model rock surfaces [9]. Although a complete understanding of the wettability alteration by LSW remains elusive at present, theories such as pH effect, multicomponent ionic exchange, and double layer expansion have been proposed, and many of them center on the modification of the thin brine films between oil and rock surfaces in OBR systems [10,11].…”

“…Altering the wettability of rock surfaces from a more oil-wet state to a more water-wet state is widely postulated as a major mechanism for LSW [3,5,6]. The wettability change has been confirmed by various experiments including chromatographic wettability tests, contact angle measurements, spontaneous imbibition tests, core flooding, etc [7]. Apart from these experimental works, the wettability alteration process has been modeled and captured by using empirical relations between wettability and salt solution parameters [8], taking into account surface reactions mechanistically [7], and focusing on the kinetics of oil detachments from model rock surfaces [9].…”

 Brine-Dependent Recovery Processes (Smart-Water/Low-Salinity-Water) in Carbonate and Sandstone Petroleum Reservoirs: Review of Laboratory-Field Studies, Interfacial Mechanisms and Modeling Attempts

“…The model showed good consistency with experimental observations and through sensitivity studies, they concluded that ion species, ionic strength and parameters, like oil acidity, reaction equilibrium constants, total surface sites and diffusion coefficient, play such a key role in the wettability alteration mechanisms. They extended the model by including limestone mineral dissolution/precipitation reactions [273]. Here, the interpolation was carried out using surface concentrations of desorbed carboxylic acid (equation 18).…”

Performance of low-salinity water flooding for enhanced oil recovery improved by SiO2 nanoparticles

“…Low-salinity water (LSW) flooding has been suggested as an effective method for enhancing oil recovery (EOR) in sandstone reservoirs when the salinity of the injection fluids is between 1400 and 5000 ppm (Alotaibi et al 2010;Austad et al 2010;Buikema et al 2011;Hilner et al 2015;Lager et al 2008b;Morrow and Buckley 2011;Piñerez Torrijos et al 2016;Qiao et al 2016;Vledder et al 2010) and although most of the experiments were done below 100 °C, there appeared to be no limitation on temperature (Lager et al 2008a). Low-salinity water flooding may be considerably effective in special conditions and is recommended for increasing oil recovery when the following are encountered: clay must be present in the sandstones, polar components (acidic and/or basic material) present in crude oil, and formation water must contain divalent ions like Ca 2+ (Lager et al 2007;Tang and Morrow 1999).…”