Experimental phase equilibrium data are presented for three reservoir oils at conditions approximating those encountered in in-situ thermal recovery processes. The fluid systems involved consist of three major groups of components: flue gas, water, and crude oil. Data were measured at temperatures from 204.4 to 371.1°C (400 to 700°F) and pressures from 6996.0 to 20785.6 kPa (1,000 to 3,000 psia). Experimental phase equilibrium data were used to develop a correlation of binary interaction coefficients of crude-oil fractions required for the Peng-Robinson equation of state. Phase equilibrium data predicted using the Peng-Robinson equation of state, using our interaction coefficients, are compared with experimental data. Generally, the Peng-Robinson equation of state predictions were in close agreement with the experimental data. Effect of feed gas/oil ratio and water/oil ratio on the equilibrium coefficients was examined through the Peng-Robinson equation of state. A study on the feasibility of representing the crude oil by only two fractions was made also. This study includes a procedure for lumping the crude-oil fractions and examples showing the importance of mixing rules in determining the pseudo critical properties of lumped fractions. Introduction The steady growth of commercial thermal recovery processes1 has created a need for basic data on phase equilibria that involve water and hydrocarbons ranging from methane to high boiling-point fractions. The in-situ thermal recovery processes often are operated at pressures above 6800 kPa (1,000 psia) and temperatures above 200°C (400°F). Experimental data and theoretical correlations on phase equilibria approximating these systems are virtually nonexistent. Early work by White and Brown2 dealt with high boiling-point hydrocarbon phase equilibria. However, the highest pressure studied was 6894.8 kPa (1,000 psia) and the lightest component was pentane. Poettmann and Mayland,3 on the basis of an empirical correlation,4 constructed charts of equilibrium coefficients, or K values, as functions of pressure and temperature for various boiling-point fractions. But the maximum pressure studied was 6894.8 kPa (1,000 psia). Later, Hoffmann et al.5 studied phase behavior of a gas-condensate system with the highest pressure reaching 20 684.3 kPa (3,000 psia) but the highest temperature investigated was only 94.2°C (201°F). In 1963, Grayson and Streed6 reported experimental vapor/liquid equilibrium data for high-temperature and high-pressure hydrocarbon systems. They also extended the Chao-Seader correlation to cover the higher temperature ranges. However, the. major light component in Grayson and Streed's system was hydrogen. Recently, because of the increasing activity in carbon dioxide flooding processes, the phase equilibria of systems involving carbon dioxide and crude oil has received attention. Simon et al.7 studied phase behavior and other properties of carbon-dioxide/reservoir-oil systems. Shelton and Yarborough8 examined phase behavior in porous media during carbon dioxide or rich-gas flooding. No extensive data on equilibrium coefficients were reported in those papers, and the temperature ranges (out of physical reality) were below 93.5°C (200°F). None of these papers surveyed included water as a component.

This paper presents the formulation and applications of a two-dimensional two-phase beta-type numerical model for simulating oil and gas reservoir performance where fluid compositional effects are significant. The model utilizes PVT data as functions of pressure and a compositional parameter to reflect changes in fluid composition parameter to reflect changes in fluid composition resulting from dry gas injection. The model differs from previous beta-type simulators for approximating compositional effects in that it accounts for the reduced tendency of oil to vaporize as light ends are removed by continued contact with dry gas. A simple linear compositional model is used to compute the changing fluid properties in each cell as injection gas mixes with in-place fluid during a series of constant pressure displacements. The simple-model data are correlated against the cumulative pore volumes of injected gas contacting each cell at various points in time for each pressure level. By tracking this parameter for each cell in the two-dimensional beta-type model the spatial and time variations of fluid properties with pressure and injection gas throughput are computed in the model from the correlations. Special provisions are included for gas condensate systems above their dew-point pressure and for reservoir oil systems above their bubble-point pressure. A comparison is made with results from a previously published fully compositional simulator. It is shown that, in addition to yielding quite similar computed compositional effects, the beta-type simulator attains an advantage in computing speed of at least 3 to 1 over a July compositional simulator. Example applications are presented for gas injection in an oil reservoir and for retrograde liquid recovery by dry gas sweep at a Pressure considerably below the dew point of a gas-condensate reservoir. Introduction Conventional beta-type numerical simulators have been used for many years to simulate the performance of so-called "black oil" reservoirs. The term "black oil" denotes oil of medium to heavy gravity at moderate temperature and pressure. Such oils can be reasonably approximated as binary fluid systems where the amount of gas dissolved in the oil is merely a function of reservoir pressure and temperature. For these systems the reservoir gas phase is assumed to contain no recoverable liquids phase is assumed to contain no recoverable liquids when flashed through surface separates. Moreover, the further assumption is made that injected gas combines with reservoir oil exactly as does in-place reservoir gas, disregarding compositional differences between the gas phases. For oils of higher gravity, existing at higher temperatures and pressures, the preceding assumptions become no longer valid. Not only does the reservoir gas phase contain a significant amount of vaporized stock-tank liquid, but injected gas can have a significant effect on the phase behavior of the reservoir hydrocarbon system. At the far end of the compositional spectrum, gas - condensate reservoirs contain the total stock-tank liquid in the vapor phase. Moreover, injected gas has a diluting effect on the liquid content as it mixes with reservoir gas. To account for the collects of mass transfer between the vapor and liquid phases, and the composition changes resulting from gas injection, several recent authors have developed fully compositional reservoir simulators. These simulators actually track individual components of a hydrocarbon fluid system, using equilibrium constants representative of the fluid compositions being studied. These fully compositional simulators are applicable to a much broader range of reservoir fluid systems than the conventional beta-type reservoir simulator. However, since the computing requirements are generally directly proportional to the number of hydrocarbon components used in the fluid system, they can be quite expensive to employ as a general purpose simulator. purpose simulator. SPEJ P. 471

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Published in Petroleum Transactions, AIME, Vol. 210, 1957, pages 27–33. Paper presented at Petroleum Branch Fall Meeting in Los Angeles, Oct. 14–17, 1956. Abstract Future depletion performance and ultimate oil recovery from reservoirs producing under volumetric control are often predicted with the aid of a material balance equation. when the reservoir fluid is very volatile, however, certain assumptions implicit in the use of the conventional methods are no longer valid. This is because laboratory differential vaporization test procedures do not adequately represent the reservoir depletion process and the performance of surface separation facilities. In such cases recovery of stock tank oil per unit of pressure decline can be predicted only from a detailed knowledge of the separator conditions and the over-all composition of the fluid entering the wellbore at each stage of depletion. Surface recovery is not simply related to the total quantity of liquid flowing into the well under reservoir conditions. In order to improve predictions for reservoirs which produce volatile oils, a stepwise method of calculation has been developed. This method uses relative permeability data and multi-component flash calculations to predict oil and gas production as a function of reservoir pressure. Calculations are presented for a reservoircontaining a volatile crude oil, and predicted tank oil recovery by primary depletion is more than twice that predicted by conventional methods which are known to be adequate for ordinary black crude oils. Calculated maximum produced gas-oil ratio is less than one-fourth of the conventional prediction. Wellstream compositions have also been used to determine variation in stock tank oil composition and liquid content of the separator gas. This information is of particular importance for crude stabilization calculations and for design of gasoline plant facilities to recovery LAG and natural gasoline.

This paper presents the depletion-performance correlations developed using data from PVT studies and wellcompletion tests of 27 rich gas-condensate and volatileoil reservoir fluids. The PVT behavior for each fluid was determined experimentally in the laboratory, and the depletion performance of each fluid was then calculated. Well-completion test data consisting of reservoir pressure and temperature, initial total gas-oil ratio, and stock-tank oil gravity were used with the depletion-performance data to develop general performance correlations.Three correlations are presented. The first equation shows the empirical relation of gas in place per barrel of hydrocarbon pore space with reservoir pressure and temperature, and initial total gas-oil ratio. The second equation is the correlation of stock-tank oil in place per barrel of hydrocarbon pore space. The third equation relates stock-tank oil production (to 500-psia depletion pressure) with pressure, temperature and oil gravity. All three correlations are also presented in convenient graphical form. Gas production to 500-psia depletion pressure is approximately 92.6 per cent of the gas in place for each fluid, so no correlation was developed for gas production.