production · surface facilities
Choke Flow (Liquid)
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Inputs
psi
psi
lb/ft³
in
—
Description
Computes single-phase liquid flow rate through a wellhead or surface choke, using the incompressible-flow orifice equation — kinetic-energy pressure drop converted directly to flow rate via the choke discharge coefficient. First-principles fluid mechanics, not an empirical multiphase field correlation.
Variables
| Symbol | Unit | Description |
|---|---|---|
| q | STB/d | Liquid Flow Rate |
| p1 | psi | Pressure immediately upstream of the choke. |
| p2 | psi | Pressure immediately downstream of the choke. |
| ρ | lb/ft³ | Density of the liquid at flowing conditions. |
| d2 | in | Internal diameter of the choke bean/orifice. |
| CD | — | Empirical discharge coefficient, typically 0.6-0.9 for a sharp-edged orifice/nozzle-type choke — read from a coefficient chart or field-calibrated rather than computed here. |
Assumptions
- Single-phase liquid only — no free gas in the stream through the choke
- The pressure drop across the choke is due entirely to the kinetic-energy (velocity) change through the restriction, not friction or elevation over any meaningful length
- The discharge coefficient CD is a representative value for the specific choke geometry — supplied directly rather than computed from a chart internally
Limitations
- Single-phase liquid only — deliberately does not implement the empirical multiphase choke correlations (Gilbert 1954, Ros 1960, Baxendell 1957, Achong 1961, Sachdeva 1986) investigated and declined for this platform, the same red-flag empirical-curve-fit shape as other declined candidates (sw_archie, buckling_limit) — a well producing meaningful gas alongside liquid needs one of those correlations instead
- CD is a required direct input, not computed internally — same 'chart-derived value entered directly' pattern already used by Choke Flow (Gas) and ESP Total Dynamic Head's friction term
- Does not account for fluid compressibility even at very high pressure drops, where liquid compressibility effects can become non-negligible — a limiting-case consideration outside this calculator's intended range
Use Cases
- → Wellhead choke sizing (liquid wells): Estimate the liquid rate a given choke size will pass at a known pressure drop, for choke selection on a well producing negligible free gas.
- → Surface facility choke/valve sizing: Size a control valve or choke on a liquid-only surface line (e.g. downstream of a separator) for a target flow rate and available pressure drop.
Related Calculations
Region Notes
Global
Confirm the well is genuinely producing negligible free gas at choke conditions before relying on this single-phase result — a well below its bubble point at the wellhead needs a multiphase choke treatment instead.
References
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