The HLD‐NAC model was recently modified to match and predict microemulsion phase behavior experimental data for Winsor type III regions. Until now, the HLD‐NAC model could not generate realistic phase behavior for type II− and type II+ two‐phase regions, leading to significant saturation and composition discontinuities when catastrophe theory is applied. These discontinuities lead to significant failures in modeling surfactant applications. We modify the HLD‐NAC equations to ensure consistency over the entire composition space including type II− and II+ regions. A robust and efficient algorithm is developed that always converges and provides continuous estimates with any formation variable of tie lines and triangles for all Winsor types. Discontinuities are eliminated and limiting tie lines near critical points are determined analytically. The tuning procedure is demonstrated using several sets of experimental data. Excellent predictability of tie lines and tie triangles, and solubilization ratios are shown.

Summary 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 waterflooding (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 LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date. This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE 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 subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which 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 of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), 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 preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (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 corefloods for small-slug sizes of low salinity are explained by the 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 flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

Minimum miscibility pressure (MMP) is one of the most important parameters in the design of a successful gas flooding process. The most reliable methods to calculate the MMP are based on slim-tube experiments, 1-D slim-tube simulations, mixing cell calculations, and the analytical methods known as the method of characteristics (MOC). The calculation of MMP using MOC is the fastest method because it relies solely on finding the key tie lines in the displacement path. The MOC method for MMP estimation in its current form assumes that the composition path is a series of shocks from one key tie line to the next. For some oils, however, these key tie lines do not control miscibility and the MMP calculated using the key tie line approach can be significantly in error. The error can be as high as 5,000 psia for heavier oils or CO2 displacements at low temperature where three-phase hydrocarbon regions can exist (L1-L2-V). At higher pressures, the two- or three-phase region can split (or bifurcate) into two separate two-phase regions (L1-L2 and L1-V regions). Thus, for the MMP calculation from MOC to be correct we must calculate the entire composition path for this complex phase behavior, instead of relying on the shock assumption from one key tie line to the next. In this paper the MOC composition route is developed completely for the bifurcating phase behavior displacement using a simplified pseudoternary system that is analogous to the complex phase behavior observed for several real displacements with CO2. We develop the MOC analytical solutions by honoring all constraints required for a unique solution; velocity, mass balance, entropy, and solution continuity. The results show that a combination of shocks and rarefaction waves exist along the nontie-line path, unlike previous MOC solutions reported to date. We show that by considering the entire composition path, not just the key tie lines, the calculated MMP agrees with the mixing cell method. We also show that in this complex ternary displacement the displacement mechanism has features of both a condensing and vaporizing drive, which was thought to be possible only for gas floods with four or more components. For pure CO2 injection the solution also becomes discontinuous for oils that lie on the tie-line envelope curve. Finally, we show that shock paths within the two-phase region are generally curved in composition space and that there is no MMP for some oil compositions considered in the displacements by CO2. Recovery can be large even though the MMP is not reached.

CO 2 flooding offers a means to recover significant amounts of oil while simultaneously sequestering CO 2 . Recent methods for CO 2 geological storage have focused on CO 2 injection into deep brine aquifers, or by water-alternatinggas (WAG) injection in a miscible gas flooding process using vertical wells. There is significant uncertainty in the amount of CO 2 that can be stored using these methods owing to reservoir heterogeneity and variations in reservoir/fluid parameters. It would be useful therefore to have a more robust process that can also increase both CO 2 storage and oil recovery in a symbiotic relationship, where increased storage leads to greater oil recovery.This paper considers an alternative process that maximizes both storage and oil recovery simultaneously using only horizontal wells in a gravity-enhanced miscible process. A reduced-order model (ROM) is developed to consider a wide range of reservoir heterogeneities and fluid properties. Monte-Carlo simulations using the ROM show that achieving very high storage and oil recovery is possible using the gravity-enhanced process and that the approach is very robust. For example, after 2.0 moveable pore volumes injected (MPVI), probabilistic forecasts show that CO 2 storage efficiency across two standard deviations ranges from about 81 to 93%, indicating that nearly all of the available pore space (excluding immobile water) at the end of injection is occupied by CO 2 . Oil recoveries after 2.0 MPVI varied from 79% to 93% of the original mass of oil-in-place (OOIP). These storage and recovery efficiencies are significantly greater than any process reported to date. Response functions developed can also be used to estimate the maximum amount of stored CO 2 and corresponding oil recoveries for a wide range of reservoir and fluid properties. Such estimates are critical for regional and national assessment of CO 2 storage potential.

Summary Commercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation. This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land's model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.