How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?
- C. Shah Kabir (Chevron ETC) | Julian J. Pop (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 2007
- Document Type
- Journal Paper
- 644 - 656
- 2007. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 5.2 Reservoir Fluid Dynamics, 4.3.3 Aspaltenes, 4.1.5 Processing Equipment, 5.6.1 Open hole/cased hole log analysis, 4.6 Natural Gas, 5.2.2 Fluid Modeling, Equations of State, 5.8.8 Gas-condensate reservoirs, 4.6.3 Gas to liquids, 4.2 Pipelines, Flowlines and Risers, 5.6.4 Drillstem/Well Testing, 4.6.2 Liquified Natural Gas (LNG), 5.1.5 Geologic Modeling, 4.1.2 Separation and Treating
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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.
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.
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