515 formation 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 above equation introduces two new properties of the oil, the formation volume factor and the solution gas oil ratio, which will now be explained. 

As solution gas is liberated, the oil shrinks. A particularly important relationship exists between the volume of oil at a given pressure and temperature and the volume of the oil at stock tank conditions. This is the oil formation volume factor (B, measured in rb/stb or rm /stm ). 

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... 

Figure 5.24 Solution GOR and Formation Volume Factor vs. pressure...

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 ... 

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. 

Laboratory observation of volatile oils will reveal an initial oil formation volume factor greater than 2.0 res bbl/STB. The oil produced at point 2 of Figure 5-2 will shrink by more than one-half, often three-quarters, on the trip to the stock tank. Volatile oils should be produced through three or more stages of surface separation to minimize this shrinkage. 

The formation volume factor was about 2.6 res bbl/STB. Does this information confirm your classification Why or why not ... 

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 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. 

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. 

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

The equations for the formation volume factor of gas, Equations 6-2 and 6-3, only apply to dry gases. These equations are not applicable to wet gases. 

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... 

Two methods for estimating formation volume factors for wet gases will be discussed. Each of the methods requires a different set of starting data. 

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

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. 

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. 

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