248 values, formation volume factor

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. 

Very often the gas compositions are unknown. Usually the volume of stock-tank gas is not known. Under these circumstances an accurate value of the formation volume factor of a wet gas can be estimated using equivalent volume, VEQ. Only the primary separator gas-oil ratio is needed. The second separator and stock-tank gas-oil ratios are ignored the VEQ correlation includes these gases. 

If the reservoir pressure could be reduced to atmospheric, the value of the formation volume factor would nearly equal 1.0 res bbl/STB. A reduction in temperature to 60°F is necessary to bring the formation volume factor to exactly 1.0 res bbl/STB. 

Since the method of processing the produced fluids has an effect on the volume of stock-tank oil, the value of the formation volume factor will depend on the method of surface processing. However, the effect is small for black oils. 

Determine the value of total formation volume factor of the black oil of Exercise 8-10 at 2400 psig. 

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. 

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. 

Figure 11-9 may be used to obtain an accurate estimate of formation volume factor of an oil at its bubble point if the producing gas-oil ratio, gas specific gravity, stock-tank oil gravity, and reservoir temperature are known.1,3 Reservoir pressure must be equal to the bubble-point pressure of the oil because the value of gas-oil ratio used to enter the chart must represent the solubility of the gas at the bubble point. If reservoir pressure is below the bubble point, some of the produced gas may come from free gas in the reservoir, and the use of producing gas-oil ratio in this correlation will give incorrect results. 

Formation volume factors computed with this correlation should be within about 5 percent of the experimentally determined values. 

EXAMPLE 11-11 Estimate values of oil formation volume factor at various pressures below bubble-point pressure for the reservoir oil of Example 11-1. 

EXAMPLE 11-12 Estimate the formation volume factor of the oil in Example 11-10 at a reservoir pressure of 5,000 psig and reservoir temperature of 22(FF. Use a value of 15.4 X 10 6 psi J for the coefficient of isothermal compressibility of the oil between 5015 psia and the bubble point. 

The accuracy of the results of the use of correlations to estimate oil formation volume factor and solution gas-oil ratio can be improved if an accurate value of bubble-point pressure is available. The method described in Chapter 9 can be used to get a reasonably accurate value of bubble-point pressure if reservoir pressure has been measured regularly during the life of the field. 

Tables of oil formation volume factor and solution gas-oil ratio tabulated against pressure are adjusted by changing the values of pressure. A delta pressure is calculated as the difference between field derived bubble-point pressure and bubble-point pressure from correlation.

First, calculate a value of gas formation volume factor at 2115 psia and 220°F. 

A black oil has a bubble-point pressure of 4000 psia at 225°F. The oil formation volume factor at the bubble point is 1.519 res bbl/STB. Estimate the oil formation volume factor at initial reservoir pressure of 6250 psia. Use a value of 13 microsips for the coefficient of isothermal compressibility. 

If reservoir pressure is reduced to atmospheric pressure, the maximum value of formation volume factor is reached. At this point temperature... 

Note that water formation volume factor can have values less than 1.0 res bbl/STB. This occurs at high reservoir pressures when the brine expansion caused by pressure decrease during the trip to the surface is greater than the brine contraction due to temperature drop and loss of gas. 

The change in volume during the pressure reduction is represented by AV, and the change in volume due to the reduction in temperature is represented by AV. Figures 16-6 and 16-7 give values of AVwp and AVwX as functions of reservoir temperature and pressure. The formation volume factor of water may be computed from these values using Equation 16-1. 

Values of formation volume factor of water estimated using this correlation agree with the limited published experimental data to within one percent. 

The formation-volume factor of gas, Bg, is calculated using Equation 6-3. Use a value of 0.63 for the specific gravity of the gas evolved from the water to determine a z-factor for Equation 6-3. This value is based on limited data and its accuracy is unknown however, it gives values which appear reasonable. 

Estimate a value of formation volume factor of the reservoir water of Exercise 16-7 at 6000 psia and 260°F. 

As was pointed out in the discussion of solution gas the value of r depends on the method of gas liberation. It is evident that the value of the formation volume factor is also dependent on the method of gas liberation, as is shown in Figure 62. Since less gas is evolved on dif-... 

Method 4- The three methods for estimating the formation volume factor that have been presented were first proposed by Katz. It is readily apparent that the computation involved becomes increasingly complex as the data available allows an increasingly accurate estimate to be made. A fourth method, which is relatively simple to apply, has been developed by Standing and requires a knowledge of the gas solubility, the gas and oil gravity, and the reservoir temperature. This method is based on experimental data obtained from 22 different California crude-oil-natural-gas mixtures and for the data employed the average error between the experimental values and those obtained by estimation was about 1.2%. 

The four methods for estimating the oil-formation volume factor that have been described are not applicable to systems above the bubble point. As already pointed out, the decrease in jS with pressure above the saturation pressure is a result of the compression of the all-liquid system. If the coefficient of compression of this liquid is known it is possible to compute the values of above the saturation pressure in tiie following manner. 

The Two-Phase Formation Volume Factor (u). In reseiwou engineering calculations it is sometimes convenient to know the volume occupied in the reservoir by one stock tank barrel of oil plus the free gas that was originally dissolved in it. This volmne is known as the two-phase fomation volume factor and is ven the symbol u. It is apparent that the value of u is determined by the values of the reservoir fluid characteristics previously described. Expressed mathematically M is defined by the following equation... 

Experimental values of the water-formation volume factor below the saturation pressure are shown in Figure 84. This chart was prepared from data obtained by Dodson and Standmg using the natural... 

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