Abstract
Vast majority of past studies that have been conducted on controlled salinity water flooding (CSWF) use diffuse layer model (DLM) that calculates only the surface potential, which can be significantly different from the ^-potential of the interface. Importantly, stability of the water-film (between the oil and the rock surface) which dictates ultimate oil recovery is related to ^-potential. As such, using DLM calculated surface potential (directly) for CSWF can be misleading. Additionally, most of the existing DLMs use integer charges instead of fractional charges to model carbonate-brine interactions, which may not represent the actual carbonate crystallographic. We present a triple layer surface complexation model (TLM) which offers the option to locate and distribute charge of the adsorbing ion(s) at three locations. TLM can therefore calculate potentials at three different locations within the Stem layer. To the best of our knowledge, only few authors have used TLM to simulate CSWF. However, some surface reactions were ignored in these models. For instance, adsorption of monovalent ions such as Na+ and Cl" ions was ignored in some of the few available TLMs. Also, the effect of basic-oil components was not considered in some TLMs, and lastly, some TLMs used integer charges for the carbonate surface group. This study introduced a comprehensive TLM that includes all these complexities. Moreover, we introduced a new wettability indicator (WI) that is related to the electrostatic forces between the oil-brine and the rock-brine interfaces. That is, WI was calculated from ζ-potentials at the oil-brine and rock-brine interfaces. The TLM, built in a geochemical simulator, PHREEQC, was then coupled with UTCHEM, a multiphase reservoir simulator. The developed simulator based on the TLM-CSWF model was tested against several experimentally measured oil recovery data sets. Results of the model suggest that Oil basic component significantly impacts oil-brine interface ζ-potential irrespective of temperature, brine composition, and ionic strength. On the otherhand, Na+ ions in brine may influence oil-brine ζ-potential, and this relates to temperature, brine composition, and ionic strength. The results further suggest that injection of (sulfate-free) diluted brine in chalk resulted to increased oil adhesion, shifting the reservoir to oil-wet condition. Hence, no additional oil is recovered with this brine injected at tertiary oil recovery stage. Finally, the results showed that wettability is related to ζ-potentials at the oil-brine and rock-brine interfaces, and the carbonate rock would be strongly oil-wet or water-wet only at significantly large magnitude of ζ-potentials at the interfaces.
NSTL