Flow Assurance

Inhibitor Injection Rate

Calculate hydrate inhibitor dosing using Hammerschmidt equation for methanol and glycol systems.

Launch Calculator Hammerschmidt equation

Methanol

K = 2,335

MW = 32.04, high losses

MEG

K = 2,335

MW = 62.07, regenerable

Corrosion

10-50 ppm

Continuous injection

Contents

Use this guide to:

  • Calculate inhibitor concentration for hydrate suppression.
  • Size methanol or glycol injection systems.
  • Determine corrosion inhibitor dosing.

1. Hammerschmidt Equation

Predicts hydrate temperature depression based on inhibitor concentration in the aqueous phase.

Hammerschmidt Equation: ΔT = K × W / (M × (100 - W)) Solved for concentration: W = 100 × M × ΔT / (K + M × ΔT) Where: ΔT = Hydrate temperature depression (°F) K = 2,335 (universal Hammerschmidt constant, °F form) W = Weight % inhibitor in aqueous phase (0-100) M = Molecular weight of inhibitor (g/mol)
Hydrate suppression versus inhibitor concentration for methanol, ethanol, MEG, and TEG.
Hydrate suppression vs inhibitor concentration: methanol most effective per wt%; glycols less effective but regenerable.

Inhibitor Constants

Inhibitor MW K Max W ΔT @ 25 wt%
Methanol 32.04 2,335 ~80% 24.3°F
Ethanol 46.07 2,335 ~70% 16.9°F
MEG 62.07 2,335 ~70% 12.5°F
DEG 106.12 2,335 ~65% 7.3°F
TEG 150.17 2,335 ~60% 5.2°F

Example: Methanol Concentration

Given: Need 30°F hydrate suppression using methanol K = 2,335, M = 32.04 W = 100 × 32.04 × 30 / (2,335 + 32.04 × 30) = 96,120 / 3,296 = 29.2 wt% methanol in aqueous phase

2. Methanol Injection

Methanol is effective but lost to both gas and liquid hydrocarbon phases. Total requirement = aqueous + gas losses + HC losses.

Total methanol requirement: MeOH_total = MeOH_water + MeOH_gas + MeOH_HC In aqueous phase (Hammerschmidt): MeOH_water = W × W_rate / (100 - W) [lb/day] Lost to gas phase: MeOH_gas = Kᵥ × P × Q_gas [lb/day] Where Kᵥ = vapor distribution factor (see table) Lost to hydrocarbon liquid: MeOH_HC ≈ 0.5-2% of condensate volume

Methanol Vapor Loss Factor (Kᵥ)

T (°F) 30 40 50 60 70
Kᵥ (lb/MMSCF/psi) 0.0015 0.0022 0.0032 0.0045 0.0062
Methanol distribution between aqueous, gas, and hydrocarbon phases.
Methanol distribution between phases: majority stays aqueous; gas and hydrocarbon losses rise with temperature and pressure.

Example: Methanol Injection Rate

Given: 10 MMSCFD, 50 bbl/day water, 1000 psia, 40°F Need 25 wt% MeOH in water Water mass: 50 bbl × 350 lb/bbl = 17,500 lb/day MeOH in water: = 0.25 × 17,500 / (1 - 0.25) = 5,833 lb/day MeOH to gas (Kᵥ = 0.0022 at 40°F): = 0.0022 × 1000 × 10 = 22 lb/day Total: 5,855 lb/day ÷ 6.6 lb/gal = 887 gal/day (21 bbl/day)

⚠ Safety: Methanol is toxic and flammable. Follow applicable handling codes.

3. Glycol (MEG) Injection

Glycols are preferred for pipelines because they're regenerable with minimal vapor losses.

MEG vs Methanol

Factor Methanol MEG
Effectiveness (ΔT per wt%) Higher Lower
Recovery Usually lost Regenerated (80-90%)
Vapor loss 2-10% <0.1%
HC solubility loss 1-2% <0.5%
Cost driver Operating (makeup) Capital (regen unit)
Best application Short-term, remote Long pipelines, offshore

Glycol Injection Calculation

Lean glycol injection rate: G_lean = W_water × C_rich / (C_lean - C_rich) Rich glycol concentration: C_rich = 100 × M × ΔT / (2,335 + M × ΔT) [from Hammerschmidt] Where: G_lean = Lean glycol rate (lb/day) W_water = Water production (lb/day) C_lean = Lean glycol concentration (typically 80-90 wt%) C_rich = Rich glycol concentration (from required ΔT) K = 2,335 (universal constant, °F)

Example: MEG Injection Rate

Given: 100 bbl/day water, need 25°F suppression Lean MEG = 85 wt%, M = 62.07, K = 2,335 Rich MEG concentration (Hammerschmidt): C_rich = 100 × 62.07 × 25 / (2,335 + 62.07 × 25) = 155,175 / 3,887 = 39.9 wt% Water mass: 100 bbl × 350 lb/bbl = 35,000 lb/day Lean MEG rate: G_lean = 35,000 × 39.9 / (85 - 39.9) = 1,396,500 / 45.1 = 30,965 lb/day Volume: 30,965 lb ÷ 9.3 lb/gal = 3,330 gal/day (79 bbl/day)

4. Corrosion Inhibitors

Film-forming corrosion inhibitors protect against CO₂ and H₂S attack. Dosing is typically ppm-based on produced water volume.

Dosing Rates

Application Typical Rate (ppm)
Sweet gas (CO₂ only) 10-25
Sour gas (H₂S present) 25-50
High CO₂ (>5 mol%) 50-100
Produced water systems 25-75

Injection Rate Calculation

Continuous injection: Rate (gal/day) = Q_water (bbl/day) × ppm × 42 / (ρ × 10⁶) Where: Q_water = Water production rate (bbl/day) ppm = Target concentration ρ = Inhibitor density (lb/gal), typically 8-9 42 = gal/bbl Example: 500 bbl/day water, 50 ppm, ρ = 8.5 lb/gal Rate = 500 × 50 × 42 / (8.5 × 10⁶) = 0.12 gal/day

References

  • GPSA, Section 20
  • NACE SP0106 – Internal Corrosion Control
  • API RP 14E – Offshore Platform Piping

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