Although geochemical reactions are the fundamental basis of the alkaline/surfactant/polymer (ASP) flooding, their importance is commonly overlooked and not fully assessed. Common assumptions made when modeling geochemical reactions in ASP floods include: 1) ideal solution (i.e., using molalities rather than ion activities) for the water and aqueous geochemical species 2) limiting the number of reactions (i.e., oil/alkali and alkali consumptions) rather than including the entire thermodynamically-equilibrated system 3) ignoring the effect of temperature and pressure on reactions 4) local equilibrium ignoring the kinetics. To the best of our knowledge, the significance of these assumptions has never been discussed in the literature. In this paper we investigate the importance of geochemical reactions during alkaline/surfactant/polymer floods using a comprehensive tool in the sense of surfactant/soap phase behavior as well as geochemistry.
We coupled the United States Geological Survey (USGS) state-of-the-art geochemical tool, with 3D flow and transport chemical flooding module of UTCHEM. This geochemical module includes several thermodynamic databases with various geochemical reactions, such as ion speciation by applying several ion-association aqueous models, mineral, solid-solution, surface-complexation, and ion-exchange reaction. It has capabilities of saturation index calculation, reversible and irreversible reactions, kinetic reaction, mixing solutions, inverse modeling and includes impacts of temperature and pressure on reaction constants and solubility products. The chemical flood simulator has a three phase (water, oil, microemulsion) phase behavior package for the mixture of surfactant/soap, oil, and water as a function of surfactant/soap, salinity, temperature, and co-solvent concentration. Hence, the coupled software package provides a comprehensive tool to assess the significance of geochemical assumptions typically imposed in modeling ASP floods. Moreover, this integrated tool enables modeling of variations in mineralogy present in reservoir rocks. We parallelized the geochemistry module of this coupled simulator for large-scale reservoir simulations.
Our simulation results show that the assumption of ideal solution overestimates ASP oil recovery. Assuming only a subset of reactions for a coupled system is not recommended, particularly when a large number of geochemical species is involved, as is the case in realistic applications of ASP. Reservoir pressure has a negligible effect but temperature has a significant impact on geochemical calculations. Although mineral reaction kinetics is largely a function of the temperature and in-situ water composition, some general conclusions can be drawn as follows: to a good approximation, minerals with slow rate kinetic reaction (e.g., quartz) can be excluded when modeling ASP laboratory floods. However, minerals with fast rate kinetic reactions (e.g., calcite) must be included when modeling lab results. On the other hand, in modeling field-scale applications, local equilibrium assumption (LEA) can be applied for fast rate kinetic minerals, whereas kinetics should be used for slow rate kinetic minerals.
Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high salinity brines, so it is advantageous to inject low salinity water as a preflush. Low salinity water flooding (LSW) can also improve local displacement efficiency by changing the wettability of the reservoir rock from oil wet to more water wet. The mechanism for wettability alteration for low salinity waterflooding in sandstones is not very well understood, however experiments and field studies strongly support that cation exchange (CE) reactions are the key element in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport has not been explained to date.
This paper presents the first analytical solutions for the coupled synergistic behavior of low salinity waterflooding and polymer flooding considering cation exchange reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the cation exchange of Ca2+, Mg2+ and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase flow and reactive transport model is decoupled into three simpler sub-problems, one where cation exchange reactions are solved, the second where a variable polymer concentration can be added to the reaction path and the third where fractional flows can be mapped onto the fixed cation and polymer concentration paths. The solutions are used to develop a front tracking algorithm, which can solve the slug injection problem where low salinity water is injected as a preflush followed by polymer. The results are verified with experimental data and PennSim, a general purpose compositional simulator.
The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low salinity pre-flush prior to polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned LSP flood can be as much as 10% OOIP greater than with considering polymer alone. The results show the structure of the solutions, and in particular the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in core floods for small low salinity slug sizes are explained with intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP as a cheaper and more effective way for performing polymer flooding when the reservoir wettability can be altered using chemically-tuned low salinity brine.