Natural Gas Hydrate & Inhibitor (Hammerschmidt) Calculator
Calculate natural gas hydrate equilibrium formation temperature, required temperature depression, and thermodynamic inhibitor injection rates (Methanol, MEG, DEG) per GPSA.
Pipeline Pressure & Operating Flow
Thermodynamic Inhibitor Selection
Hydrate Curve & Injection Rates
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Frequently Asked Questions
What are natural gas hydrates and how do they form?
Natural gas hydrates are crystalline, ice-like solid compounds composed of water molecules forming cage-like clathrate lattices that trap light hydrocarbon guest molecules (methane, ethane, propane, CO2). Unlike ordinary ice, hydrates form at elevated pressures well above 32°F (0°C), typically between 50°F and 70°F (10°C to 21°C) in high-pressure gas pipelines.
How does the Hammerschmidt equation calculate inhibitor dosage?
Formulated by E.G. Hammerschmidt in 1934, the equation deltaT = (KH * X) / (M * (1 - X)) relates the required hydrate temperature depression (deltaT) to the weight fraction of inhibitor (X) in the liquid water phase and the molecular weight (M) of the chemical. Lower molecular weight inhibitors like methanol (M=32) provide vastly more depression per pound than glycols (MEG M=62, DEG M=106).
Why is MEG preferred over Methanol in closed subsea loop systems?
Methanol has high vapor pressure and low boiling point, meaning 30% to 50% of injected methanol vaporizes into the gas phase and cannot be recovered economically. Monoethylene glycol (MEG) has negligible vapor loss and is easily regenerated and recycled in offshore closed-loop MEG regeneration units (MRU).