Page 408 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

374 Production

Table 6-2
-.
Tmical Comnosltions of Hydrocarbons Fluids Dl
Retrograde Volatile Oil or Black Aeay
Dry Gas Wet Gas Condensate Near Critical Oils 011 Oil
c, (mle C) 90 70 55 30
c,-c, (lm31. 8) 9 22 30 35
G+ (=le%) 1 8 t5 35
GOR[ft'/abl] m 150000 3000-150000 2000-3000 < 2000
(10000+)* (3000-6000)*
I2NJ m > 27000 540-27000 360-540 c 360
API Llquid
Gravity 40-60 45-70
Llquid Specific
RaViV 0.83-0.76 0.8-0.7

see retrograde behavior at reservoir pressures below about 2,500 psi (17.2 MPa).
Volatile oil systems are those within the two-phase region under reservoir
conditions, the vapor phase corresponding to condensate compositions and
conditions. Volatile oil is not an apt description because virtually all reservoir
fluids are volatile. What is really meant is that the reservoir fluid exhibits the
properties of an oil existing in the reservoir at a temperature near its critical
temperature. These properties include a high shrinkage immediately below the
bubble point. In extreme cases, this shrinkage can be as much as 45% of the
hydrocarbon pore space within 10 psi (0.7 bar) below the bubble point. Near-
critical oils have formation factor Bo of 2 or higher; the compositions are usually
characterized by 12.5 to 20 mole % heptanes or more.
Ordinary oils are characterized by GOR from 0 to approximately 200 ft3/bbl
(360 m3/m3) and Bo less than 2. Oils with high viscosity (about 10 cp), high oil
density and negligible gas/oil ratio are called heavy oils. At surface conditions
may form tar sands. Oils with smaller than 10 cp viscosity are known as a black
oil or a dissolved gas oil system; no anomalies are in phase behavior. There is
no sharp dividing line between each group of reservoir hydrocarbon fluid;
however, liquid volume percent versus pressure diagram (Figure 6-5) is very
useful to understand the subject.
The significant point to be made is that when an oil system exists in intimate
contact with an associated gas cap, the bubble point pressure of the oil will be
equal to the dew point pressure of the gas cap and both of those values will be
equal to the static reservoir pressure at the gas-oil contact (Figure 6-6).

Reservolr Condltions Phase Behavlor
There is one phase flow in reservoir conditions if well flowing pressure Pwf
is higher than bubble point pressure P, or dew point pressure Pb and two-phase
flow occurs by a wellbore. Reservoir depletion and production consist of two
separate processes: flash liberation (vaporization) and differential liberation. A
schematic representation of flash vaporization is shown in Figure 6-7. At stage 1
reservoir f hid is under reservoir pressure and temperature at known volumes
V,. The pressure in the cell is covered by increasing the space available in the
cell for the fluid V,. This procedure is repeated until a large change in the