This paper presents a three-dimensional, three-phase compositional model for simulating CO2 flooding including CO2 solubility in water. Both fully implicit and IMPES formulations are included. In this model, CO2 is allowed to dissolve in the aqueous phase while all other components except water exist in the oil and gas phases. Oil- and gas-phase densities and fugacities are modeled by a cubic equation of state. The aqueous phase properties are functions of the amount of dissolved CO2. CO2 solubility is computed using a CO2 fugacity coefficient table that is converted internally from input CO2 solubility data as a function of pressure at reservoir temperature. Correlations for computing the solubility of CO2 in water and other properties of CO2 saturated water are presented. Results for simulation runs with and without CO2 solubility in water are shown for comparison. IntroductIon Compositional models using a cubic equation of state are usually used to simulate the enhanced recovery process of gas injection. In most of the published models, for example Coats and Young and Stephenson, all hydrocarbon components exist in the oil and gas phases but are not allowed to dissolve in the aqueous phase. Usually, this assumption is adequate since the hydrocarbon solubility in water is low over the range of temperature and pressure for gas injection. Carbon dioxide, however, is an exception to this assumption. The solubility of CO2 in water is much higher than that of hydrocarbon components and is a factor that can not be neglected in the simulation process. This is especially true when CO2 is injected into a previously waterflooded reservoir or when CO2 is injected with water for mobility control. Tile objective of this paper is to model oil recovery processes involving CO2 injection while taking into account the effects of CO2 solubility in water. The effects of the presence of an aqueous phase on the phase behavior of CO2/hydrocarbon systems have been experimentally studied by Pollack et al. It was found that the presence of water reduces the amount of CO2 available for mixing with the hydrocarbons, and shifts the pressure-composition diagram of CO2/crude oil system. The solubility of CO2 in water is a function of temperature, pressure and water salinity. A thorough study of CO2 solubility data in distilled water was presented by Dodds et al. In general, CO2 solubility increases with pressure and decreases with temperature. An increase in salinity of the reservoir water decreases CO2 solubility significantly. Li and Nghiem used Henry's Law to estimate CO2 solubility in distilled water and used the scaled-particle theory to take into account the presence of salt in the aqueous phase. Enick and Klara also used Henry's Law to predict CO2 solubility in distilled water. Tile decreased solubility of CO2 in brine was accounted for empirically by a single factor correlated to the weight percent of dissolved solid. However, a wide scatter of data characterizes their correlation. A compositional model for simulating CO2 floods including CO2 solubility in water is presented. In this model, hydrocarbons and CO2 are allowed to exist in the oil and gas phases while only CO2 and water exist in the aqueous phase. A cubic equation of state is used to model oil- and gas-phase densities and fugacities. An input table of CO2 solubility in water, water formation volume factor, water compressibility and water viscosity is required for this model. These data, which are obtained either experimentally or generated from correlations, are entered as a function of pressure at reservoir temperature. The CO2 solubility in water is internally converted into a fugacity coefficient table as a function of pressure. The fugacity coefficients are then used to compute the amount of CO2 in water during simulation using the equality of component chemical potential constraint. The water formation volume factor, compressibility and viscosity are then computed as a function of the amount of CO2 dissolved in the water.

Abstracts This paper presents a three-dimensional, three-phase compositional model for simulating CO2 flooding including C02 solubility in water. Both fully implicit and IMPES formulations are included. In this model, C02 is allowed to dissolve in the aqueous phase while all other components except water exist in the oil and gas phases. Oil- and gas-phase densities and fugacities are modeled by a cubic equation of state. The aqueous phase properties are functions of the amount of dissolved C02. C02 solubility is computed using a C02 fugacity coefficient table that is converted internally from input C02 solubility data as a function of pressure at reservoir temperature. Correlations for computing the solubility of C02 in water and other properties of C02 saturated water are presented. Results for simulation runs with and without C02 solubility in water are shown for comparison.

The formulation of a black-oil or compositional fully coupled surface and subsurface simulator is described. It is based on replacing the well model in a conventional reservoir simulator with a generalized network model of the wells and facilities. This allows for representation of complex wellbore geometry and downhole equipment. The method avoids the inefficiencies and/or inaccuracies of other coupled models, in which wells and facilities are treated as separate domains or in which the global system is not solved simultaneously. Example cases demonstrate the performance of the model for cases with simple and segmented wellbores (with and without facilities).

The formulation of a black-oil or compositional fully coupled surface and subsurface simulator is described. It is based on replacing the well model in a conventional reservoir simulator with a generalized network model of the wells and facilities. This allows for representation of complex wellbore geometry and downhole equipment. The method avoids the inefficiencies and/or inaccuracies of other coupled models, in which wells and facilities are treated as separate domains or in which the global system is not solved simultaneously. Example cases demonstrate the performance of the model for cases with simple and segmented wellbores (with and without facilities).

The applicability and accuracy of a new binary pseudo-component PVT representation relative to conventional black-oil and equation-of-state representations is determined. This PVT representation extends the conventional black-oil treatment by decoupling the reservoir and surface PVT properties and by modeling the properties of oil and gas through the use of K-values and Z-factors for a two component system. Processes considered include depletion, water injection, and gas injection in oil reservoirs. In depletion simulations the ability of the two-component K-value (2CKV) representation to model gas phase condensation in surface separators results in higher and more accurate (relative to equation-of-state predictions) oil recovery predictions than those obtained using a conventional black-oil model. The capability of the 2CKV formulation to model time-dependent separator conditions is shown for a waterflood in a vertical cross section. Neither the 2CKV nor the black-oil formulation can accurately simulated a gas injection process when the composition of the injection gas is significantly different from the composition of equilibrium reservoir gas in the injection cell(s). Introduction Several authors have proposed modifications of black-oil models to approximate compositional effects in gas condensate and volatile oil reservoirs. These models represent various degrees of implementation of a binary pseudo-component PVT property representation. Rovere et al. proposed an "alpha-beta" model which differs from conventional black-oil models in the treatment of surface separation. Differential liberation data without adjustment are assumed to represent PVT behavior in the reservoir. Gas phase condensation during separation is modeled through the use of two pressure-dependent parameters, alpha and beta. Conventional black-oil surface volume rates are given by: (1) (2) Rovere et al. modified these equations as: (3) (4) Alpha represents the fraction of reservoir free gas produced as gas in the separator, and beta represents the oil produced per unit of free gas due to free gas condensation. The parameters alpha and beta are determined by equation-of-state prediction. The two component K-value model presented here differs from previous work in the representation of reservoir and separator PVT properties. The compositional treatment of the gas phase allows modeling of gas phase composition variations in the reservoir and provides a means for modeling gas phase condensation in the separator(s) without requiring any data in addition to that for conventional black-oil simulation. DESCRIPTION OF MODELS In order to guarantee consistency in comparisons of simulation results, the three models used in this study are identical except for the hydrocarbon phase PVT property representations. PVT properties in the compositional model are calculated using the Peng-Robinson Equation-of-State. P. 665^