Modeling Low Salinity Waterflooding in Mineralogically Different Carbonates

Abstract

Injection of low salinity brines can improve oil recovery (IOR) in carbonate reservoirs by changing the rock wettability from oil-wet to more water-wet. Existing numerical simulation models for low salinity flooding use empirical relationships that do not properly capture important processes for wettability alteration, such as aqueous species concentrations, oil acidity, and rock mineralogy. In our previous research on modeling spontaneous imbibition with tuned water (SPE170966), we developed a process-based and predictive model that explicitly includes the chemical interactions between crude oil, brine, and the carbonate surface. In this research, we extend the previous model for low salinity water flooding to both chalk and limestone cores. We examine the role of mineralogy in low salinity waterflooding by developing a mechanistic model for wettability that includes surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite. The reactions coupled with the equations of multiphase flow and transport are solved simultaneously using an IMPEC 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 (Fathi et al. 2010), a limestone with small amount of anhydrite (Austad et al. 2012), and a Middle Eastern carbonate with 6% volume fraction anhydrite (Yousef et al. 2011) are used to tune the reaction network and make recovery predictions. Simulation results give remarkable agreement with the effluent concentrations of SO42−, Ca2+ and Mg2+ reported from chromatographic wettability tests and the recoveries for injection of various brines into chalk and limestone cores of differing compositions. For SK chalk without anhydrite, reducing the Na+ and Cl– concentration of seawater, while keeping SO42− (sulfate) leads to improved oil recovery (IOR) by as much as 6% OOIP. The presence of anhydrite, which provides a natural source of sulfate, also significantly increased oil recovery for injection of diluted formation water and seawater. Simulations of 2D five-spot patterns using tuned reaction networks demonstrated that IORs from 5% to 20% OOIP can be obtained at reasonable values of pore volumes injected (2.0 PVI). These IORs depend greatly 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.

Mechanisms of smart waterflooding in carbonate oil reservoirs - A review

“…Alexeev (2015) and Eftekhari et al (2017) indicated a correlation between the residual oil saturation and amounts of the adsorbed sulfate ions, while (contrary to the expectations) a correlation with concentrations of other potential determining ions is not that clear. This is confirmed by observations of Qiao et al (2015), who account for mineralogy of the rock. In this study, it is shown that the recovery improvement is correlated with the amount of anhydrite, which is considered as a source for sulfate.…”

“…A system of flow equations describing all the physical mechanisms discussed above may only be solved numerically. Several attempts have been carried out to match available experimental data by solutions of such systems (Alexeev, 2015;Andersen et al, 2012;Eftekhari et al, 2017;Evje et al, 2009;Madland et al, 2011;Qiao et al, 2015). Complexity of the described process results in a relatively large number of adjustment parameters.…”

Thermodynamic Analysis of Chalk–Brine–Oil Interactions

“…The major gap, however, is a link between the physical aspects of these mechanisms and the transport properties (i.e., relative permeability) of the aqueous and oleic phase in porous media. Until now, this gap is filled by using empirical relations, often with one or few unknown parameters that are later estimated by fitting the model to the core flooding experimental data (also known as history matching [11][12][13][14] ).…”

Chemical Compositions in Salinity Waterflooding of Carbonate Reservoirs: Theory

“…To account for aqueous equilibrium reactions, we conserve element masses (Felder and Rousseau 2005;Al-Shalabi et al 2014). During frontal displacement in a 1D reactive porous medium, conservation of element i demands that (Yeh and Tripathi 1991;Steefel and Lasaga 1994;Walter et al 1994;Qiao et al 2015;Eftekhari et al 2017) ϕ…”