production · surface facilities
Choke Flow (Gas)
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Inputs
psi
psi
°F
—
—
in
—
Description
Computes gas flow rate through a wellhead or surface choke using the standard isentropic compressible-flow equations for sonic (critical) and subsonic (subcritical) flow — first-principles gas dynamics, not an empirical multiphase field correlation. Automatically determines which regime applies by comparing the downstream/upstream pressure ratio against the critical pressure ratio, then applies the matching closed-form equation.
Variables
| Symbol | Unit | Description |
|---|---|---|
| qsc | Mscf/d | Gas Flow Rate |
| yc | — | Critical Pressure Ratio |
| pup | psi | Pressure immediately upstream of the choke (e.g. flowing tubing/wellhead pressure). |
| pdn | psi | Pressure immediately downstream of the choke (e.g. flowline pressure), measured a short distance away from the restriction itself. |
| Tup | °F | Gas temperature immediately upstream of the choke. |
| γg | — | Gas specific gravity relative to air (air = 1.0). |
| k | — | Ratio of specific heats (Cp/Cv) for the gas — about 1.25-1.3 for typical produced natural gas. |
| d2 | in | Internal diameter of the choke bean/orifice/nozzle. |
| CD | — | Empirical discharge coefficient, read from a nozzle- or orifice-type choke coefficient chart (function of Reynolds number and choke/pipe diameter ratio — e.g. Crane 1957) rather than computed here. 0.62 is this calculator's own worked-example value for an orifice-type choke at high Reynolds number. |
Assumptions
- Flow through the choke is adiabatic and effectively reversible (isentropic) — no meaningful heat transfer or friction loss occurs across the short restriction itself
- The gas behaves as a real gas well-characterized by its specific gravity and specific heat ratio alone — no separate compressibility (Z-factor) term appears in this specific field-unit formulation
- Single-phase gas only — no liquid present in the stream through the choke; a well producing liquid alongside gas needs a multiphase choke treatment, deliberately out of scope here (see limitations)
- The discharge coefficient CD is a representative value for the specific choke type/size/Reynolds-number combination — supplied directly rather than computed from a chart internally
Limitations
- Single-phase gas 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: those are field-data curve-fits (of the form pwh=C·R^m·q/S^n) with no first-principles derivation, the same red-flag shape as other declined candidates on this platform (sw_archie, buckling_limit) — a well producing meaningful liquid alongside gas needs one of those correlations instead, not this calculator
- CD (discharge coefficient) is a required direct input, not computed internally — it depends on choke geometry (nozzle vs. orifice type) and Reynolds number via a chart (Crane 1957) or correlation this calculator does not implement, the same 'chart-derived value entered directly' pattern already used by ESP Total Dynamic Head's friction term
- Downstream temperature (relevant for hydrate/icing risk at the choke) is not computed here — a real, separate consideration for gas choke design not covered by this rate calculation
Use Cases
- → Wellhead choke sizing: Estimate the gas rate a given choke size will pass at known upstream/downstream pressures, for choke selection or production-rate control.
- → Regime diagnosis: Determine whether a choke is operating in sonic (rate-stabilizing, downstream-pressure-independent) or subsonic flow for a given set of conditions.
Related Calculations
Region Notes
Global
Sonic (critical) flow is the normal, desired operating condition for a production choke — it stabilizes wellhead rate against downstream flowline pressure fluctuations. Confirm which regime applies before relying on a fixed choke setting for rate control.
References
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