Page 145 - PVT Property Correlations

122 PVT Property Correlations

unavailable. The correlations for volatile oil are given in Appendix A, Oil
Correlations Formulae.

HANDLING PVT PROPERTIES FOR VOLATILE OILS
Most volatile oil PVT properties can be determined from a reservoir fluid
study. While five PVT experiments are usually performed for black oil fluids
[composition measurement, constant composition expansion (CCE), differen-
tial liberation (DL), viscosity measurement, and separator experiment(s)],
many recent PVT reports for volatile oil fluids include the results of an addi-
tional experiment [constant volume depletion (CVD)]. The PVT experiments
are explained in other texts (e.g., Ahmed, 2016; Whitson and Brule, 2000).
Unlike in black-oil PVT experiments, DL experiment alone is believed to be
inadequate to explain the volatile oil behavior in the reservoir. CVD is added
in modern volatile oil PVT reports to give more experimental observations
that can be used to build reliable EOS models. The only PVT property that
requires additional calculations is vaporized oil gas ratio (R v ). Walsh and
Towler (1994) presented a direct method to calculate the volatile oil PVT
properties from the CVD experiment data. Other methods are also available,
but require the use of a tuned EOS model for the fluid. Fattah et al. (2006)
compared the most commonly used methods for calculating MBO properties
and concluded that Whitson and Torp (1983) yields slightly better results
than other methods.
If PVT reports and EOS models are not available, correlations can be
used to estimate PVT properties for volatile oil. In general, the correlations
reviewed in Chapter 7, Black Oils, can be used for volatile oils. These corre-
lations include those for bubble point pressure, solution GOR, oil formation
volume factor, oil density, oil viscosity, and isothermal compressibility of
oil. The correlations for the free gas released in the reservoir when the pres-
sure declines below the bubble point pressure can also be used to handle the
free gas properties below the bubble point pressure. In addition to these cor-
relations, the two R v correlations (El-Banbi et al., 2006; Nassar et al., 2013)
can be used for vaporized oil gas ratio calculation.
Input data for correlations is the same for volatile oil and black oil fluids.
However, it is more difficult sometimes to prepare volatile oil input data for
correlations.
While it is relatively easy to estimate bubble point pressure from field
data for black oils (when enough static reservoir pressure points are avail-
able), it is usually difficult to estimate bubble point pressure from field data
in volatile oil reservoirs. This difficulty is due to the fact that reservoir pres-
sure declines gently above and below the bubble point in volatile oil reser-
voirs. In black oil reservoirs, two distinct lines with significantly different
slopes can usually be observed when static reservoir pressure is plotted
against time or against cumulative oil production.