Solution Gas-Oil Ratio, Rso

The amount of gas dissolved in an oil at a given pressure and temperature is referred to as the solution gas-oil ratio (R_so), in units of SCF/STB. The solubility of natural gas in crude oil depends on the pressure, temperature, and composition of the gas and the crude oil. For a particular gas and crude oil at constant temperature, the quantity of solution gas increases with pressure, and at constant pressure, the quantity decreases with increasing temperature. For any temperature and pressure, the quantity of solution gas increases as the compositions of the gas and crude oil approach each other—that is, it will be greater for higher specific gravity gases and higher API gravity crudes. Unlike the solubility of, say, sodium chloride in water, gas is infinitely soluble in crude oil, the quantity being limited only by the pressure or by the quantity of gas available.

Crude oil is said to be saturated with gas at any pressure and temperature if, on a slight reduction in pressure, some gas is released from the solution. Conversely, if no gas is released from the solution, the crude oil is said to be undersaturated at that pressure. The undersaturated state implies that there is a deficiency of gas present and that, had there been an abundance of gas present, the oil would be saturated at that pressure. The undersaturated state further implies that there is no free gas in contact with the crude oil (i.e., there is no gas cap).

Gas solubility under isothermal conditions is generally expressed in terms of the increase in solution gas per unit of oil per unit increase in pressure (e.g., SCF/STB/psi or dR_so/dp). Although for many reservoirs, this solubility figure is approximately constant over a considerable range of pressures, for precise reservoir calculations, the solubility is expressed in terms of the total gas in solution at any pressure (e.g., SCF/STB, or R_so). It will be shown that the reservoir volume of crude oil increases appreciably because of the solution gas, and for this reason, the quantity of solution gas is usually referenced to a unit of stock-tank oil and the solution gas-oil ratio (R_so) is expressed in standard cubic feet per stock-tank barrel. Figure 2.8 shows the variation of solution gas with pressure for the Big Sandy reservoir fluid at reservoir temperature 160°F. At the initial reservoir pressure of 3500 psia, there is 567 SCF/STB of solution gas. The graph indicates that no gas is evolved from the solution when the pressure drops from the initial pressure to 2500 psia. Thus the oil is undersaturated in this region, and there can be no free gas phase (gas cap) in the reservoir. The pressure 2500 psia is called the bubble-point pressure, for at this pressure bubbles of free gas first appear. At 1200 psia, the solution gas is 337 SCF/STB, and the average solubility between 2500 and 1200 psia is

Figure 2.8 Solution gas-oil ratio of the Big Sandy Field reservoir oil, by flash liberation at reservoir temperature of 160°F.

The data of Fig. 2.8 were obtained from a laboratory PVT study of a bottom-hole sample of the Big Sandy reservoir fluid using a flash liberation process.

It will be shown that the solution gas-oil ratio and other fluid properties depend on the manner by which the gas is liberated from the oil. The nature of the phenomenon is discussed together with the complications it introduces into certain reservoir calculations. For the sake of simplicity, this phenomenon is ignored and a stock-tank barrel of oil is identified, with a barrel of residual oil following a flash liberation process, and the solution gas-oil ratios by flash liberation are used.

Estimating a value for the solution gas-oil ratio, R_sob, at the bubble point requires information about the conditions at which the surface separator is operating. If the separator pressure and temperature are not available, then Valko and McCain propose the following equation to estimate R_sob²⁰:

where

R_so,SP = solution gas-oil ratio at the exit of the separator

When laboratory analyses of the reservoir fluids are not available, it is often possible to estimate the solution gas-oil ratio with reasonable accuracy. Velarde, Blasingame, and McCain give a correlation method from which the solution gas-oil ratio may be estimated from the reservoir pressure, the reservoir temperature, the bubble-point pressure, the solution gas-oil ratio at the bubble-point pressure, the API gravity of the tank oil, and the specific gravity of the separator gas.²¹ The correlation involves the following equations:

where

R_sob = solution gas-oil ratio at the bubble-point pressure, STB/SCF

p = pressure, psia

p_b = pressure at the bubble-point, psia

γ_g,SP = specific gravity of the separator gas

ρ_o,API = gravity of the stock-tank oil, °API

T = temperature, °F

The gravity of the stock-tank oil is frequently reported as a specific gravity relative to water at 60°F. The equation used to convert from specific gravity to units of °API is

If the density is reported in °API and is needed in lb/ft³, then rearrange Eq. (2.27) and solve for the specific gravity. The specific gravity is then multiplied by the density of water at 60°F, which is 62.4 lb/ft³.