Mechanistic modeling of low salinity water injection
MetadataShow full item record
Petroleum and Geosystems EngineeringLow salinity waterflooding is an emerging enhanced oil recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher salinity waterflooding. Although there are many low salinity experimental results reported in the literature, publications on modeling this process are rare. While there remains some debate about the mechanisms of low salinity waterflooding, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Since no comprehensive geochemical-based modeling has been applied in this area, we decided to couple a state-of-the-art geochemical package, IPhreeqc, developed by the United States Geological Survey (USGS) with UTCOMP, the compositional reservoir simulator developed at the Center for Petroleum and Geosystems Engineering in The University of Texas at Austin. A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, non-isobaric and both local-equilibrium and kinetic conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components (e.g., CO2, CH4, and acidic/basic components of the crude) on buffering the aqueous pH and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constrains are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low salinity waterflooding. The geochemical module of UTCOMP-IPhreeqc is further parallelized to enable large scale reservoir simulation applications. We hypothesize that the total ionic strength of the solution is the controlling factor of the wettability alteration due to low salinity waterflooding in sandstone reservoirs. Hence, a model based on the interpolating relative permeability and capillary pressure as a function of total ionic strength is implemented in the UTCOMP-IPhreeqc simulator. We then use our integrated simulator to match and interpret a low salinity experiment published by Kozaki (2012) (conducted on the Berea sandstone core) and the field trial done by BP at the Endicott field (sandstone reservoir). On the other hand, we believe that during the modified salinity waterflooding in carbonate reservoirs, calcite is dissolved and it liberates the adsorbed oil from the surface; hence, fresh surface with the wettability towards more water-wet is created. Therefore, we model wettability to be dynamically altered as a function of calcite dissolution in UTCOMP-IPhreeqc. We then apply our integrated simulator to model not only the oil recovery but also the entire produced ion histories of a recently published coreflood by Chandrasekhar and Mohanty (2013) on a carbonate core. We also couple IPhreeqc with UTCHEM, an in-house research chemical flooding reservoir simulator developed at The University of Texas at Austin, for a mechanistic integrated simulator to model alkaline/surfactant/polymer (ASP) floods. UTCHEM has a comprehensive three phase (water, oil, microemulsion) flash calculation package for the mixture of surfactant and soap as a function of salinity, temperature, and co-solvent concentration. Similar to UTCOMP-IPhreeqc, we parallelize the geochemical module of UTCHEM-IPhreeqc. Finally, we show how apply the integrated tool, UTCHEM-IPhreeqc, to match three different reaction-related chemical flooding processes: ASP flooding in an acidic active crude oil, ASP flooding in a non-acidic crude oil, and alkaline/co-solvent/polymer (ACP) flooding.