fluid_properties · gas properties
Gas Viscosity
μg = K×10⁻⁴×exp(X·ρg^Y) [cP], Lee-Gonzalez-Eakin (1966)
click formula to derive ↑
Inputs
°F
psi
—
—
Description
Computes natural gas viscosity from the Lee-Gonzalez-Eakin (1966) correlation, which relates μg to gas density (via P, T, Z, and molecular weight) through an empirical exponential fit. Gas viscosity is required for gas well deliverability, non-Darcy flow, and pressure-transient analysis.
Variables
| Symbol | Unit | Description |
|---|---|---|
| μg | cP | Gas Viscosity |
| T | °F | Reservoir temperature at which viscosity is evaluated. |
| P | psi | Reservoir pressure at which gas density (and hence viscosity) is evaluated. |
| γg | — | Gas specific gravity (air = 1.0), used to compute apparent molecular weight M = 28.97·γg. |
| Z | — | Gas compressibility factor at P and T, from gas_zfactor or a lab/chart value. |
Assumptions
- Sweet natural gas of the composition Lee-Gonzalez-Eakin's dataset represents — no correction is applied for unusual non-hydrocarbon content
- Z-factor supplied (e.g. from gas_zfactor) is accurate at the P and T of interest — viscosity error propagates directly from Z error
- Single gas phase — no condensate liquid drop-out altering effective composition
Limitations
- The original 1966 paper's fitted T/P/gravity envelope was not independently re-verified against the primary source this session — treat this as reliable for typical reservoir gas conditions (moderate pressure, 100–300°F) but no fittedRange warning is authored on the inputs; this is a disclosed gap, not an assertion of unlimited validity
- Not valid for retrograde condensate liquid-rich streams where composition changes with pressure
- As with any viscosity correlation, lab-measured μg should be preferred for high-value well test or deliverability work
Use Cases
- → Gas well deliverability: Supply μg to pseudo-pressure and non-Darcy (turbulence) gas well test analysis, where viscosity strongly affects both laminar and turbulent flow terms.
- → Pressure-transient analysis: Provide μg for the gas diffusivity equation used in build-up/drawdown analysis of gas wells.
- → Wellbore multiphase flow: Use μg alongside oil_viscosity in multiphase pressure-drop correlations for gas-condensate or gas-lift wells.
Related Calculations
Region Notes
Global
Typical reservoir natural gas (γg 0.6–0.8) at 2,000–8,000 psi and 150–300°F gives μg ≈ 0.015–0.030 cP — roughly an order of magnitude lower than reservoir oil viscosity, which is why gas wells can sustain much higher flow rates for the same drawdown.
Haynesville
High-pressure, high-temperature dry gas (>10,000 psi, >300°F) pushes ρg and μg toward the upper end of the correlation's practical range — cross-check against lab PVT data where available.
References
Primary source
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