Hydrate Inhibition — Engineering Fundamentals
Hammerschmidt & K-S-W, MeOH vs MEG, partition losses, when the correlation breaks down.
1. Thermodynamic inhibition
Natural gas hydrates form when water and certain low-molecular-weight gases (CH₄, C2H6, C3H8, CO₂, H₂S) co-exist at high pressure and low temperature. The thermodynamic stability boundary depends on the activity of liquid water — adding a strong polar solvent (methanol, glycols, salts) reduces water activity and shifts the boundary to lower temperatures. This is a colligative property — fewer water molecules in the liquid means a lower hydrate formation temperature at the same pressure.
The shift is parameterized as ΔT (suppression), the difference between the hydrate-formation T of pure water and that of the inhibited solution at the same operating P.
2. Hammerschmidt 1934
Hammerschmidt fitted natural-gas pipeline data from the 1930s to a simple two-parameter model:
W is mass percent of inhibitor in the free-water phase. The constant K_H is empirical and inhibitor-specific:
| Inhibitor | MW (g/mol) | KH | Effective per wt % |
|---|---|---|---|
| Methanol (MeOH) | 32.04 | 2335 | Highest ΔT per wt % |
| MEG (ethylene glycol) | 62.07 | 2700 | ~half of MeOH; recoverable |
| DEG | 106.12 | 4000 | Rare for inhibition; in dehy use |
| TEG | 150.17 | 5400 | Dehydration absorber chemistry |
| Salts (NaCl, CaCl₂) | — | — | K_H form does not apply; use Najibi correlation |
Validity: 0 < ΔT < ~36 °F (20 °C). Above 36 °F suppression, Hammerschmidt under-predicts and rigorous methods (Nielsen-Bucklin, McKoy-Sinanoğlu, or full equation-of-state with CSMHYD/CSMGem) should be used.
3. MeOH vs MEG vs LDHIs
| Property | MeOH | MEG | LDHI (kinetic / anti-agglomerant) |
|---|---|---|---|
| Suppression per wt % | ~1 °F/wt % | ~0.5 °F/wt % | Doesn't suppress — delays nucleation |
| Recoverable? | No (distillation impractical) | Yes (regen to ≥95 wt %) | No (single-pass) |
| Vapor losses | High (1–10 lb/MMscf) | Negligible | Negligible |
| NGL losses | Significant (10–40 wt % of liquid HC has MeOH) | Low | Low |
| Capex | Low (drum + pump) | High (regenerator + filter + reboiler) | Low |
| Best for | Wellhead, short pipeline, intermittent | Long subsea tieback, continuous | Cold-stab oil, very-long lines |
For short, low-flow systems (well-pad, satellite), MeOH wins because the regenerator CAPEX never pays back. For deep-water tiebacks (50+ km, 20+ MMscfd), MEG with regen is the standard — losses are too costly without it. LDHIs are kinetic hydrate inhibitors (KHIs, polymeric) or anti-agglomerants (AAs, surfactants); they keep the system in the hydrate region but delay/disperse nucleation — work in narrow operating windows.
4. Vapor & NGL losses
Methanol partition is a real cost — methanol vapor in the gas-phase exits the system (no recovery), and methanol dissolved in the condensate/NGL phase requires water-wash to reclaim. K-S-W (Katz-Sloan-Wettlaufer) charts give partition coefficients:
- Gas-phase MeOH: 0.5–10 lb/MMscf at 500–1500 psia (lower at higher P, lower T).
- NGL-phase MeOH: 5–40 wt % of free-water MeOH partitions into HC liquid; recovered only by water wash.
The calculator includes the vapor loss term (user-adjustable) but not the NGL partition — for full economic comparison MEG-vs-MeOH on a long pipeline, multiply the MeOH dose by a 1.3–1.6 safety factor to account for losses below the Hammerschmidt mass-balance minimum.
5. References
- Hammerschmidt, E.G. (1934). "Formation of gas hydrates in natural gas transmission lines." Ind. Eng. Chem. 26(8), 851–855.
- Katz, D.L.; Sloan, E.D.; Wettlaufer, J.S. (1959). "Vapor-liquid equilibria for water-methanol-hydrocarbon systems."
- GPSA Engineering Data Book §20 — Dehydration & Hydrate Inhibition.
- Sloan, E.D.; Koh, C.A. (2008). Clathrate Hydrates of Natural Gases, 3rd ed. CRC Press.
- Nielsen, R.B.; Bucklin, R.W. (1983). "Why not use methanol for hydrate control?" Hyd. Proc. 62(4), 71–78.