Reservoir volume factor

Formation volume factor also is known as reservoir volume factor. The reciprocal of the formation volume factor sometimes is called gas expansion factor. Unfortunately, the term formation volume factor is used occasionally when gas expansion factor is meant. The engineer must always examine the units to be sure which is intended. 

Formation volume factor also is called reservoir volume factor. 

In gas reservoir engineering, the gas expansion factor, E, is commonly used. However, in oil reservoir engineering it is often more convenient to refer to the gas formation volume factor which is the reciprocal E, and is expressed in units of scf/stb (using field units). The reason for this will become apparent in Section 8. 

This section will firstly consider the properties of oils in the reservoir (compressibility, viscosity and density), and secondly the relationship of subsurface to surface volume of oil during the production process (formation volume factor and gas oil ratio). 

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 formation volume factor for water (B, reservoir volume per stock tank volume), is close to unity (typically between 1.00 and 1.07 rb/stb, depending on amount of dissolved gas, and reservoir conditions), and is greater than unity due to the thermal contraction and evolution of gas from reservoir to stock tank conditions. 

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 flowrate of oil into the wellbore is also influenced by the reservoir properties of permeability (k) and reservoir thickness (h), by the oil properties viscosity (p) and formation volume factor (BJ and by any change in the resistance to flow near the wellbore which is represented by the dimensionless term called skin (S). For semisteady state f/owbehaviour (when the effect of the producing well is seen at all boundaries of the reservoir) the radial inflow for oil into a vertical wellbore is represented by the equation ... 

Print buffers 3X SSC, 3X SSC + 50% DMSO, and 3X SSC + 1.5 M betaine were evaluated at 40, 60, and 80% RH for spot intensity, spot diameter, intraspot variation, and CV (Figure 4.35). The reductions in quill drop volumes and droplet drying times were measured by video microscope and the quill reservoir volume changes determined by weight. In summary, "Solvent evaporation from the print buffer reservoir is the major factor responsible for the variations in the transfer of fluid to fhe slide surface."... 

Obviously this objective is not unique to North Sea production platforms. Barring certain peculiar circumstances it is always desirable, within economic limits, to maximize the recovered barrels of stock tank oil per unit volume of well stream production. This has the effect of increasing the ratio of barrels of stock tank oil to barrels of reservoir oil, which is defined as the formation volume factor. 

Laboratory analysis will indicate an initial oil formation volume factor of 2.0 res bbl/STB or less. Oil formation volume factor is the quantity of reservoir liquid in barrels required to produce one stock-tank barrel. Thus, the volume of oil at point 2 of Figure 5-1 shrinks by one-half or less on its trip to the stock tank. 

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. 

Fig. 6-1. Typical shape of gas formation volume factor as a function of pressure at constant reservoir temperature.

The shape of a plot of gas formation volume factor versus reservoir pressure at constant temperature for a typical dry gas is given in Figure 6-1. 

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. 

The formation volume factor of a wet gas is defined as the volume of reservoir gas required to produce one stock-tank barrel of liquid at the surface. By definition... 

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. 

The first of these numbers divided by the second gives the volume of stock-tank liquid which comes from 1 lb mole of reservoir gas. This number divided into the molar volume of the reservoir gas gives the formation volume factor. 

EXAMPLE 7-8 Continue Example 7-4 by calculating wet gas formation volume factor at reservoir 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. 

The change in oil volume due to these three factors is expressed in terms of tins, formation volume factor of oil. Oil formation volume factor is defined as the volume of reservoir oil required to produce one barrel of oil in the stock tank. Since the reservoir oil includes dissolved gas,... 

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. 

Another way to express formation volume factor of oil is that it is the volume of reservoir occupied by one STB plus the gas in solution at reservoir temperature and pressure. 

The relationship of formation volume factor of oil to reservoir pressure for a typical black oil is given in Figure 8-1. 

This figure shows the initial reservoir pressure to be above the bubble-point pressure of the oil. As reservoir pressure is decreased from initial pressure to bubble-point pressure, the formation volume factor increases slightly because of the expansion of the liquid in the reservoir. 

A reduction in reservoir pressure below bubble-point pressure results in the evolution of gas in the pore spaces of the reservoir. The liquid remaining in the reservoir has less gas in solution and, consequently, a smaller formation volume factor. 

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. 

The formation volume factor may be multiplied by the volume of stock-tank oil to find the volume of reservoir oil required to produce that volume of stock-tank oil. The shrinkage factor can be multiplied by the reservoir volume to find the corresponding stock-tank volume. Both terms are in use, but petroleum engineers have adopted universally the formation volume factor. 

The volume of oil at the lower pressure is B0. The quantity of gas evolved is the quantity in solution at the bubble point, Rsb, minus the quantity remaining in solution at the lower pressure, Rs. The evolved gas is called free gas. It is converted to reservoir conditions by multiplying by the formation volume factor of gas, Bg. 

Figure 8-4 gives a comparison of total formation volume factor with the formation volume factor of oil. The two formation volume factors are identical at pressures above the bubble-point pressure since no gas is released into the reservoir at these pressures. 

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. 

A black oil reservoir has just been discovered. Reservoir pressure appears to be above the bubble-point pressure of the oil. Measured at reservoir conditions, 86,3 barrels per day enter the wellbore. The oil is processed through a separator into a stock tank. The stock tank accumulates 57.9 barrels of 44.2°API oil each day. The separator produces 43,150 scf/d of 0.724 gravity gas, and the stock tank vents 7240 scf/d of 1.333 gravity gas. What is the formation volume factor of the oil What is the solution gas-oil ratio Which of the previous answers applies at the bubble point ... 

This chapter begins with bubble-point pressure and solution gas-oil ratio, and then explains methods of estimating the density of reservoir liquids. The results of the density calculations are used to estimate oil formation volume factors. A technique for adjusting the results of the correlations to fit field derived bubble-point pressure is presented. 

The results of the reservoir liquid density calculations can be used to calculate oil formation volume factors. 

When the composition of the reservoir liquid is known, oil formation volume factor can be calculated very accurately using the procedure given in Chapter 13. The other two situations will be discussed here. 

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. 

If the solution gas-oil ratio is known at some pressure below the bubble point, it can be used to enter Figure 11-9, and an accurate estimate of the oil formation volume factor at that reservoir pressure can be determined. Solution gas-oil ratio can be obtained from Figure 11-1. However, the accuracy of the final result is a combination of the 5 percent attributed to Figure 11-8 and the 15 percent attributed to Figure 11-1. 

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. 

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