production · tubing performance
Flowing Bottomhole Pressure (Tubing Traverse)
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Inputs
psi
ft
—
STB/d
in
cp
in
Description
Computes flowing bottomhole pressure (Pwf) by tracing a single-phase liquid pressure traverse up the tubing string from a known wellhead pressure — summing the hydrostatic head of the fluid column and the friction pressure loss from flow. Reynolds number and Darcy friction factor are computed internally from the same physical inputs (rate, tubing ID, density, viscosity, roughness) rather than requiring the user to run the standalone Reynolds Number and Friction Factor calculators separately first — the same 'compute the sub-term internally' pattern ESP Total Dynamic Head already uses for its own submergence term.
Variables
| Symbol | Unit | Description |
|---|---|---|
| Pwf | psi | Flowing Bottomhole Pressure |
| ΔP | psi | Tubing Pressure Drop |
| Pwh | psi | Flowing wellhead (surface tubing) pressure — the traverse's starting point at the top of the tubing string. |
| TVD | ft | True vertical depth of the tubing string over which the pressure traverse is evaluated (vertical well assumed). |
| SG | — | Specific gravity of the flowing liquid (water = 1.0), used for both the hydrostatic and friction terms. |
| Q | STB/d | Liquid production rate through the tubing. |
| d | in | Tubing internal diameter. |
| μ | cp | Viscosity of the flowing liquid at tubing conditions. |
| ε | in | Absolute roughness of the tubing's internal surface. 0.0018 in (0.0457 mm) is the standard commercial steel value. |
Assumptions
- Single-phase liquid flow throughout the tubing string — no free gas evolving or flowing alongside the liquid; a well producing significant gas needs the (deferred) multiphase gradient treatment instead
- Vertical well — tubing length is treated as equal to true vertical depth; a significantly deviated wellbore's measured depth and TVD differ, and this calculator does not distinguish them
- SG, viscosity, and roughness are representative single values for the full tubing length — no allowance for property changes with depth (e.g., temperature-dependent viscosity)
Limitations
- Explicitly single-phase liquid only — not valid for a well producing meaningful free gas alongside liquid; that requires a multiphase pressure-gradient correlation (deferred, see the Multiphase Gradient research findings), not this calculator
- Assumes a vertical wellbore; deviated or horizontal completions need a true measured-depth-based traverse this calculator does not provide
- Reynolds number and friction factor are computed internally and not exposed as separate results here — use the standalone Reynolds Number and Friction Factor calculators directly if those intermediate values themselves are of interest
Use Cases
- → Estimating Pwf without a bottomhole gauge: Estimate flowing bottomhole pressure from a measured wellhead pressure when no downhole pressure gauge is available, for use in IPR calculations (Productivity Index, Vogel, Standing, Fetkovich, Composite IPR all require Pwf as an input).
- → Tubing sizing sensitivity: Compare Pwf and the friction/hydrostatic split across different tubing IDs to evaluate whether a smaller or larger completion changes deliverability meaningfully.
Related Calculations
Region Notes
Global
Hydrostatic head dominates total tubing pressure drop for most single-phase liquid wells at typical rates — friction usually becomes significant only at high rate, small tubing ID, or unusually rough/scaled tubing, as flagged in this calculator's own result note.
References
Primary source
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