production · tubing performance
Gas Velocity (Tubing)
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Inputs
Mscf/d
ft³/scf
in
Description
Computes the actual (in-situ) gas velocity in production tubing, converting the standard-condition gas rate to its true flowing volume via the gas formation volume factor before dividing by the tubing's cross-sectional flow area. Using the standard-condition rate directly (without the Bg correction) would overstate velocity dramatically, since gas at typical flowing tubing pressure occupies a small fraction of its standard-condition volume.
Variables
| Symbol | Unit | Description |
|---|---|---|
| v | ft/s | Gas Velocity |
| q | Mscf/d | Gas production rate measured at standard surface conditions. |
| Bg | ft³/scf | Gas formation volume factor at the flowing pressure/temperature of interest — converts the standard-condition rate to its actual (in-situ) volume in the tubing. Run the Gas FVF (Bg) calculator first and carry its result in here (see relatedCalcs); using the standard-condition rate directly, without this correction, overstates velocity by roughly two orders of magnitude at typical tubing flowing pressures. |
| d | in | Tubing internal diameter at the point where velocity is being evaluated. |
Assumptions
- Bg is representative of the actual flowing pressure and temperature at the point of interest, not reservoir conditions — a single Bg value does not capture how velocity changes along the tubing string as pressure drops toward surface
- Single-phase gas flow — no free liquid loading in the tubing at the point of evaluation
- The tubing ID is the actual current internal diameter, not nominal/new-pipe specification
Limitations
- A single Bg value gives velocity at one point only — gas expands continuously as pressure drops up the tubing, so velocity increases toward surface; evaluate at multiple depths (or at the most restrictive/highest-velocity point of interest) rather than treating this as a single well-wide figure
- Does not itself flag erosional velocity limits against a specific API RP 14E constant — the result note includes a generic 50 ft/s screening flag, not a rigorous erosional-velocity calculation
- Assumes dry gas with no liquid loading; a wellbore accumulating liquid at low gas rates needs a liquid-loading (critical velocity) analysis this calculator does not perform
Use Cases
- → Erosional velocity screening: Check actual in-situ gas velocity against erosional or liquid-loading velocity limits at a given point in the tubing string.
- → Multiphase gradient correlation input: Superficial gas velocity is a required building-block input for multiphase pressure-gradient correlations (e.g., Beggs-Brill), which combine it with superficial liquid velocity to characterize the flow regime.
Related Calculations
Region Notes
Global
Always source Bg from the actual flowing pressure/temperature at the point of interest, not reservoir pressure — the two can differ substantially and using reservoir-condition Bg will misrepresent tubing velocity.
References
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