Summary
Collection and analysis of gas/condensate-fluid samples presents
considerable challenges. This is because downhole sampling of a gas/condensate
fluid—unlike its oil counterpart—does not guarantee the retrieval of a
single-phase fluid. The same is true for surface sampling because of incomplete
surface and/or downhole separation. Given this reality, the
pressure/volume/temperature (PVT) analysis of any fluid sample with an
equation-of-state (EOS) model demands that the results are verified with
independent measurements.
Our analyses of many samples show that a good correspondence exists between
the PVT-derived gradient and that obtained from wellbore-flow modeling of
production-test data. Older-generation formation testers (those from before
1990), although yielding comparable results, had larger error bars because of
system limitations in repeatability of both pressure and depth
measurements.
We developed a yield/temperature correlation to fill in the information void
for reservoirs that fall within the bounds of measured data over a large
geographic area. Correlating CO2 with formation temperature was a stepping
stone to the yield/temperature relationship. This approach is applicable for
the analysis of both single-reservoir and multireservoir samples, which is
particularly useful when rapid assessment is needed over large regions.
Introduction
The presence of a compositional gradient in reservoirs containing
hydrocarbon columns has long been recognized since Sage and Lacey (1939)
published their seminal work. Segregation of asphaltenes causes compositional
grading in oil (20–30°API) columns. In contrast, compositional grading in
light-hydrocarbon (> 35°API) columns occurs for near-critical fluids or,
more appropriately, for fluids close to the spinodal curve (Lira-Galeana 1992).
Equilibrium between gravitational and chemical forces of various hydrocarbon
components results in a variable saturation pressure in a fluid column (Schulte
1980; Riemens et al. 1988; Wheaton 1991). According to Hirschberg (1988), the
time to reach such an equilibrium (10 million to 1 billion years) is comparable
to the geologic time of a typical reservoir.
A number of authors have reported field experiences with compositional
grading in gas/condensate reservoirs (Creek and Schrader 1985; Smith et al.
2004; Ghorayeb et al. 2003). Ordinarily, the equilibrium approach appears to
explain gradients observed in the field. In reality, however, heat flux can
potentially prevent attaining true equilibrium in a hydrocarbon column because
of the temperature gradient in a reservoir (Pedersen and Lindeloff 2003; Hoier
and Whitson 2001; Ghorayeb and Firoozabadi 2000a and 2000b; Firoozabadi 1999).
Irreversible thermodynamics appears to explain compositional grading in most
systems. In this study, we will assume that thermal diffusion does not play a
dominant role in distributing hydrocarbon components in the fluid columns
studied.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
6 March 2006
- Meeting paper published:
15 May 2006
- Revised manuscript received:
20 June 2007
- Manuscript approved:
30 June 2007
- Version of record:
20 December 2007
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