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.
CO2 miscible injection is generally one of the most efficient enhanced oil recovery (EOR) methods and widely used in the conventional oil reservoirs. The applicability of CO2 EOR technology for unlocking the resources from unconventional tight and shale formations and the mechanisms of miscible flooding in these reservoirs still remain unclear. An important parameter used to evaluate the feasibility of CO2 miscible flooding is the minimum miscibility pressure (MMP). Even though experimental approaches, empirical correlations and theoretical methods have performed well in measuring or predicting MMP between CO2 and crude oil in conventional reservoirs, they may not be suitable for unconventional formations as phase behavior and MMP can be significantly affected by confinement effect in small pores (e.g., nanopores) in such formations.
In this study, a new MMP prediction model based on the modified Parachor Model associated with the Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) is developed to determine CO2 MMP both in the bulk phase and nanopores. The Parachor Model is modified to account for the confinement effect of nanopore walls on the equilibrium interfacial tension (IFT). The Equilibrium IFT reduction in nanopores is related to a temperature-dependent and slit pore width-dependent modification term. The parameters of the new Parachor Model are determined by matching the vapor-liquid surface tension values for CH4, C2H6, C3H8,
The newly developed model successfully reproduces MMP in bulk phase as compared with both other methods and experimental data. The overall average absolute relative deviation (AARD) for MMP is within 8 %. The calculated equilibrium IFT for liquid-vapor phase has a good agreement with molecular simulation results. For Bakken oil-CO2 system, if the slit pore width is larger than 10 nm, MMP is independent on pore width; otherwise, it decreases significantly with the decrease of the pore width. If pore width decreases to 3 nm, 67.5 % decrease in the IFT is observed and 23.5% reduction is achieved for MMP between Bakken oil and CO2 stream, indicating that it is easier to reach miscibility in nanopores, and CO2 miscible flooding might be a promising enhanced oil recovery (EOR) technology for tight oil and shale oil reservoirs. Furthermore, MMP increases with an increase of temperature in bulk phase, whereas IFT and MMP decrease with an increase of temperature in nanopores.
Jin, Luchao (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Li, Zhitao (The University of Texas at Austin) | Luo, Haishan (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Shiau, Ben (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior.
This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model.
The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.