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

Contents

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 (Rigorous): μ_JT = f(P_r, T_r) × (T_pc/P_pc) × (1/C_p) Where: f(P_r, T_r) = 2.343 × T_r^(-2.04) - 0.071 × P_r + 0.0568 Reference: ACS Omega (2021) Temperature drop: ΔT = μ_JT × ΔP (or step-wise integration for ΔP > 150 psi) T₂ = T₁ - ΔT Typical μ_JT: 0.06–0.08 °F/psi (6–8 °F per 100 psi for lean gas)
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.

Rigorous Calculation Method

The calculator uses peer-reviewed correlations for professional-grade accuracy:

Parameter Method Reference
Pseudo-critical properties T_pc = 170.5 + 307.3×SG
P_pc = 709.6 - 58.7×SG		 Sutton (1985) SPE 14265
J-T coefficient f(P_r,T_r) × (T_pc/P_pc) × (1/C_p) ACS Omega (2021)
Hydrate temperature Katz + Towler-Mokhatab averaged Katz (1945), Towler (2005)
Large pressure drops Step-wise integration (ΔP > 150 psi) Accounts for varying μ_JT

Accuracy: J-T coefficient ±5-10%, Hydrate temperature ±2-4°F for SG 0.55-0.90, P 100-2000 psia. For critical/safety applications, verify with process simulator (HYSYS, ProMax) using rigorous EOS.

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.

Hydrate Temperature Correlations

The calculator uses two validated correlations, averaged for best accuracy:

Katz (1945) - fitted to GPSA charts: T_h = -54.5 + 13.1×ln(P) + 40×γ [°F] Towler-Mokhatab (2005): T_h = 13.47×ln(P) + 34.27×ln(γ) - 1.675×ln(P)×ln(γ) - 20.35 [°F] Where: P = pressure (psia), γ = gas specific gravity Accuracy: ±2-4°F for SG 0.55-1.0, P 100-2000 psia

Validation Points

Pressure (psia) SG Katz Towler-M GPSA Chart
400 0.65 50.0°F 49.9°F 50-54°F
1000 0.65 62.0°F 62.9°F 60-64°F
1000 0.70 64.0°F 64.4°F 62-66°F
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

  1. Get μ_JT from composition, T₁, P₁ (use EOS or chart)
  2. Calculate ΔT = μ_JT × ΔP (integrate for large ΔP)
  3. Determine T₂ = T₁ - ΔT
  4. Compare T₂ to hydrate curve at P₂
  5. 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

  • Sutton, R.P. (1985). "Compressibility Factors for High-Molecular-Weight Reservoir Gases." SPE 14265.
  • ACS Omega (2021). "Influences of Hydrogen Blending on the Joule-Thomson Coefficient of Natural Gas." doi:10.1021/acsomega.1c00248
  • Katz, D.L. (1945). "Prediction of Conditions for Hydrate Formation in Natural Gases." Trans. AIME, 160, 140-149.
  • Towler, B. & Mokhatab, S. (2005). "Quickly Estimate Hydrate Formation Conditions in Natural Gases." Hydrocarbon Processing, 84:61-62.
  • GPSA, Sections 13 & 20
  • Campbell Gas Conditioning and Processing, Vol. 2

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