Simulation of tertiary carbon dioxide injectivity

Injectivity is a key variable for determining the economic and technical incentives associated with a proposed enhanced oil recovery project, but tertiary carbon dioxide ({dollar}rm COsb2){dollar} and brine injectivity during water-alternating-gas (WAG) displacements above the {dollar}rm COsb2{dollar} minimum miscibility pressure (MMP) cannot be reliably predicted on the basis of viscosity ratios and waterflood injectivity performance alone. The purposes of this study are to develop methods to scale laboratory measurements in order to determine their implications for reservoir injectivity, to develop methods to interpret field pilot tests, and to improve our ability to predict reservoir injectivity. Approximate analytical models based upon gravity-free displacement with nondispersive plug flow of constant composition slugs in noncommunicating radial layers have been used to interpret injectivity during reservoir tests as a function of relative permeability, flow geometry, effective wellbore radius, and layering. We then compared the analytical solutions with numerical calculations made using an equation-of-state compositional simulator, UTCOMP, developed at The University of Texas, in order to examine the effects of phase behavior, dispersive mixing, gravity, capillary forces, viscous instability, crossflow, and relative permeability on injectivity for channeling-dominated displacements in a reservoir cross section with a simple layered representation. These calculations showed that the relative permeability parameters can have important effects on injectivity, and that phase behavior and mixing caused by physical dispersion and crossflow should not be neglected when modeling reservoir-scale displacements. We have presented a more realistic and comprehensive analysis than is available in the literature of the influence of relative permeability on injectivity. These effects are summarized in the form of a systematic sensitivity study that shows the importance of each parameter and identifies those features that are diagnostic of lower {dollar}rm COsb2{dollar} injectivity.; We have also modified UTCOMP to enable detailed modeling of reservoir-scale cross sections that incorporate geostatistical representations of reservoir heterogeneity and radial flow near injection and production wells. The compositional simulator was then used to interpret an injectivity test conducted in a high-heterogeneity carbonate reservoir in the San Andres formation of west Texas. Field injectivity was significantly greater than initial waterflood injectivity during all WAG cycles, increased during each {dollar}rm COsb2{dollar} cycle, and was greater than other field tests in the San Andres formation or from available laboratory data. An important implication of this study is the validation of compositional simulation and the methods presented here as practical methods for interpreting field tests and developing improved predictions of reservoir injectivity performance. Accurate prediction of reservoir injectivity based upon laboratory and reservoir characterization data appears to be possible. Another significant conclusion is that geostatistical techniques can be used successfully to characterize high heterogeneity in carbonate reservoirs for tertiary {dollar}rm COsb2{dollar} and brine injectivity calculations.