Page 140 - Hydrocarbon Exploration and Production Second Edition

Reservoir Description 127

6.2.5.2. Oil viscosity
Oil viscosity is an important parameter required in predicting the fluid flow, both in
the reservoir and in surface facilities, since the viscosity is a determinant of the
velocity with which the fluid will flow under a given pressure drop. Oil viscosity is
significantly greater than that of gas (typically 0.2–50 cP compared to 0.01–0.05 cP
under reservoir conditions).
Unlike gases, liquid viscosity decreases as temperature increases, as the molecules
move further apart and decrease their internal friction. Like gases, oil viscosity
increases as the pressure increases, at least above the bubble point. Below the bubble
point, when the solution gas is liberated, oil viscosity increases because the lighter
oil components of the oil (which lower the viscosity of oil) are the ones which
transfer to the gaseous phase.
The same definition of viscosity applies to oil as gas, but sometimes the kinematic
viscosity is quoted. This is the viscosity divided by the density (u ¼ m/r), and has a
straight-line relationship with temperature.

6.2.5.3. Oil density
Oil density at surface conditions is commonly quoted in 1API, as discussed in Section
6.2.2. Recall,
141:5
API ¼ 131:5
g
o
where g o is the specific gravity of oil (relative to water ¼ 1, measured at STP).
The oil density at surface is readily measured by placing a sample in a cylindrical
flask and using a graduated hydrometer. The API gravity of a crude sample will be
affected by temperature because the thermal expansion of hydrocarbon liquids is
significant, especially for more volatile oils. It is therefore important to record the
temperature at which the sample is measured (typically the flowline temperature or
the temperature of the stock tank). When quoting the gravity of a crude, standard
conditions should be used.
The downhole density of oil (at reservoir conditions) can be calculated from the
surface density using the equation:
r B o ¼ r þ R s r
orc o g
3
where r orc is the oil density at reservoir conditions (kg/m ), B o the oil formation
3
3
3
volume factor (rm /stm ), r o the oil density at standard conditions (kg/m ), R s the
3
3
3
solution GOR (sm /stm ) and r g the gas density at standard conditions (kg/m ).
The density of the oil at reservoir conditions is useful in calculating the gradient of
oil and constructing a pressure–depth relationship in the reservoir (see Section 6.2.8).
The previous equation introduces two new properties of the oil, the formation
volume factor and the solution GOR, which will now be explained.
6.2.5.4. Oil formation volume factor and solution gas:oil ratio
Assuming an initial reservoir pressure above the bubble point (undersaturated
3
reservoir oil), only one phase exists in the reservoir. The volume of oil (rm or rb) at