Gas Processing

Joule-Thomson Valve Cooling

Calculate temperature drop across throttling valves. Essential for hydrate prevention and NGL recovery.

Launch calculator J-T coefficients

Typical μ_JT

6-8 °F/100 psi

Lean natural gas

Hydrate risk

<60°F

At pipeline pressures

Safety margin

10-15°F

Above hydrate temp

1. J-T Effect
2. J-T Coefficients
3. Hydrate Risk
4. Applications

Use this guide to:

Calculate temperature drop across valves.
Prevent hydrate formation.
Design pressure letdown stations.

1. The Joule-Thomson Effect

Gas expanding through a valve without external work (isenthalpic process) changes temperature. Natural gas at typical conditions cools on expansion.

J-T Coefficient: μ_JT = (∂T/∂P)_h [°F/psi] Temperature drop: ΔT = μ_JT × ΔP T₂ = T₁ - ΔT Typical μ_JT: 0.04–0.08 °F/psi (4–8 °F per 100 psi)

J-T valve schematic showing pressure drop and cooling across the valve. — J-T valve expansion schematic: upstream/downstream pressures, isenthalpic drop, and resulting cooling.

Sign Convention

Condition	μ_JT	Effect
Normal operation (T < 300°F)	> 0	Gas cools on expansion
Above inversion temp (~800°F+)	< 0	Gas heats on expansion
Ideal gas	= 0	No temperature change

2. J-T Coefficients

Coefficient varies with gas composition, temperature, and pressure. Heavier gas = lower μ_JT = less cooling.

Joule-Thomson coefficient versus temperature at various pressures. — J-T coefficient vs temperature at multiple pressures for lean gas; higher pressure and temperature reduce μ_JT.

Coefficient by Gas Type

Gas Type	SG	μ_JT (°F/100 psi)	ΔT for 500 psi drop
Pure Methane	0.55	6.5–7.0	32–35°F
Lean Gas	0.60	6–8	30–40°F
Medium Gas	0.70	5–7	25–35°F
Rich Gas	0.80	4–6	20–30°F
Very Rich / NGL	0.90+	3–5	15–25°F

Conditions: ~80°F, 500-1000 psia. Use EOS for accurate values.

Example Calculation

Given: P₁ = 800 psia, T₁ = 80°F, P₂ = 300 psia
       Gas SG = 0.60 (lean), μ_JT = 6.5 °F/100 psi

ΔP = 800 - 300 = 500 psi

ΔT = 6.5 × (500/100) = 32.5°F

T₂ = 80 - 32.5 = 47.5°F

→ Gas cools to 47.5°F — check hydrate curve at 300 psia

3. Hydrate Risk Assessment

J-T cooling often drops gas temperature into hydrate formation zone. Always check outlet temperature against hydrate curve.

J-T cooling path on hydrate pressure-temperature diagram showing safe and hydrate zones. — J-T cooling path on a hydrate P-T diagram; keep the outlet on the safe side of the hydrate curve.

Prevention Methods

Method	Application	Notes
Dehydration	Plants, pipelines	<7 lb/MMSCF (glycol); <1 ppm (mol sieve for cryo)
Upstream heating	Pressure letdown	Line heater before valve
Methanol injection	Wellheads, intermittent	20-50 wt% in water; high vapor losses
MEG injection	Subsea, continuous	50-80 wt%; regenerable
LDHI	Subsea tiebacks	Kinetic/AA; 0.5-2 wt%

⚠ Design rule: Outlet temperature must be ≥10°F above hydrate formation temperature at outlet pressure. If not, apply mitigation.

4. Applications & Design

Common Applications

Application	Typical ΔP	ΔT (approx)	Mitigation
NGL plant inlet	200-400 psi	15-30°F	Gas/gas exchanger pre-cool
Wellhead choke	1000-3000 psi	60-200°F	Multi-stage, heating, MeOH
Pipeline letdown	400-800 psi	25-50°F	Line heater, dehydration
Fuel gas regulation	100-300 psi	8-20°F	Often none if dehydrated

Design Procedure

Get μ_JT from composition, T₁, P₁ (use EOS or chart)
Calculate ΔT = μ_JT × ΔP (integrate for large ΔP)
Determine T₂ = T₁ - ΔT
Compare T₂ to hydrate curve at P₂
Apply mitigation if margin < 10°F

Common Errors

Constant μ_JT: Coefficient varies with T and P. Integrate for ΔP > 300 psi.
"Dry" gas assumption: Gas at 7 lb/MMSCF still forms hydrates if cooled below dew point.
Ignoring ambient losses: Exposed piping adds cooling beyond J-T effect.
Material limits: A106-B steel limited to -20°F; use impact-tested steel below.

References

GPSA Engineering Data Book, Sections 13 & 20
Campbell Gas Conditioning and Processing, Vol. 2
GPA Midstream 2145 – Physical Constants