Formation volume factor calculation

The oil formation volume factor at initial reservoir conditions (B., rb/stb) is used to convert the volumes of oil calculated from the mapping and volumetries exercises to... 

The other parameters used in the calculation of STOMP and GIIP have been discussed in Section 5.4 (Data Interpretation). The formation volume factors (B and Bg) were introduced in Section 5.2 (Reservoir Fluids). We can therefore proceed to the quick and easy deterministic method most frequently used to obtain a volumetric estimate. It can be done on paper or by using available software. The latter is only reliable if the software is constrained by the geological reservoir model. 

The gas formation volume factor is defined as the volume of gas at reservoir conditions required to produce one standard cubic foot of gas at the surface. Units vary. Sometimes units of reservoir cubic feet per standard cubic foot, res cu ft/scf, are used. Reservoir cubic feet simply represents the gas volume measured or calculated at reservoir temperature and reservoir pressure. Often the units are reservoir barrels of gas per standard cubic foot, res bbl/scf. 

Formation volume factor of a gas may be calculated as the volume occupied by the gas at reservoir temperature and pressure divided by the volume occupied by the same mass of gas at standard conditions. 

EXAMPLE 6-3 Calculate a value of the formation volume factor of a dry gas with a specific gravity of 0.818 at reser >oir temperature of220°F and reservoir pressure of 2100 psig. 

Calculate the formation volume factor of the ethane of Example 3-7 at 918 psia and U7°F. 

If the compositions of die produced gases and liquid are known and the producing gas-oil ratios are available, the composition of the reservoir gas may be calculated as in Example 7-1. The results of such a recombination calculation can be used to calculate the formation volume factor. The volume of gas in the reservoir and the volume of stock-tank liquid must be calculated. 

EXAMPLE 7-6 Continue Example 7-1 by calculating wet gas formation volume factor at resei voir conditions of2360 psig and 204°F. 

Calculate the wet gas formation volume factor of the gas of Exercise 7-1 when reservoir conditions are 6500 psia and 225°F. 

We now turn to black oils. We consider those physical properties which are required for the reservoir engineering calculations known as material balance calculations. These properties are formation volume factor of oil, solution gas-oil ratio, total formation volume factor, coefficient of isothermal compressibility, and oil viscosity. Also, interfa-cial tension is discussed. 

EXAMPLE 8-2 A sample of reservoir liquid with volume of 400 cc under reservoir conditions was passed through a separator and into a stock tank at atmospheric pressure and 6CTF. The liquid volume in the stock tank was 274 cc. A total of 1.21 scf of gas was released. Calculate the oil formation volume factor. 

EXAMPLE 8-4 Exactly one stock-tank barrel was placed in a laboratory cell. 768 scf of gas was added. Cell temperature was raised to 220°F, the cell was agitated to attain equilibrium between gas and liquid, and pressure was raised until the final bubble of gas disappeared. At that point cell volume was 1.474 barrels and pressure was 2620 psig. Pressure in the cell was reduced to 2253 psig by increasing total cell volume to 1.569 barrels. At that point the oil volume in the cell was 1.418 barrels and the gas volume in the cell was 0.151 barrels. Calculate the total formation volume factor at 2253 psig. 

Formation volume factors and solution gas-oil ratios normally are not measured for volatile oils. These quantities are used primarily in material balance calculations which do not apply to volatile oils. If these quantities were measured for volatile oils, they would have the shapes indicated in Figures 8-10 and 8-11. The large decreases in both curves... 

A liquid sample from a black oil reservoir had a volume of 227.0 cc in a laboratory cell at reservoir temperature and bubble-point pressure. The liquid was expelled through laboratory equipment which is the equivalent of the field separator-stock tank system. The oil volume collected in the stock tank was 167.4 cc. The separator produced 0.537 scf of gas, and the stock tank produced 0.059 scf of gas. Calculate the formation volume factor of the oil and the solution gas-oil ratio. 

The first step in calculating fluid properties is selection of separator conditions. There may be circumstances for a particular field which dictate a specific separator pressure. If not, the separator pressure which produces the maximum amount of stock-tank liquid is selected. This pressure is known as optimum separator pressure. It is identified from the separator tests as the separator pressure which results in a minimum of total gas-oil ratio, a minimum in formation volume factor of oil (at bubble point), and a maximum in stock-tank oil gravity ( API). Most black oils have optimum separator pressures of 100 to 120 psig at normal temperatures. 

The value of fonnatipn volume factor of oil at the selected separator pressure is BoSb in the following calculations. The corresponding value of total gas-oil ratio is Rssb- Bosb will be used as the formation volume factor of oil at the bubble point, Bot,. 11 will be used as the solution gas-oil ratio at the bubble point, Rsb. 

At pressures above bubble-point pressure, oil formation volume factors are calculated from a combination of flash vaporization data and separator test data. 

EXAMPLE 10—5 Calculate formation volume factors of oil for Good Oil Co. No. 4. Use optimum separator conditions. 

Gas formation volume factors are calculated with z-factors measured with the gases removed from the cell at each pressure step during differential vaporization. Equation 6-2 is used. Usually Bg values as calculated are listed in the report. 

Calculate solution gas-oil ratio, relative oil volume, relative total volume, z-factor, and formation volume factor of gas at 1100 psig for the differential vaporization of Example 10-2. 

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