Hydrate Inhibition & Inhibitor Injection Rate — Engineering Fundamentals

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 (GPSA §20: K_H = 2335 for methanol; 2335–4000 for glycols):

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

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. Methanol Injection Rate Sizing

Inhibition theory gives the concentration needed in the free-water phase; sizing the injection system requires the total rate, which adds the methanol lost to the gas and hydrocarbon-liquid phases. Methanol is effective but partitions into all three phases, so total requirement is the sum:

In aqueous phase (Hammerschmidt mass balance):
  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 (table below)

Lost to hydrocarbon liquid:
  MeOH_HC    ≈ 0.5–2% of condensate volume

Solving Hammerschmidt for the required aqueous concentration:

Example — methanol concentration for 30 °F suppression
  K = 2335 (universal form), M = 32.04
  W = 100 × 32.04 × 30 / (2335 + 32.04 × 30)
    = 96,120 / 3,296
    = 29.2 wt % methanol in the aqueous phase

Note: this worked example uses the simplified universal K = 2335 form. For higher accuracy, use the inhibitor-specific K_H values from the table in Section 2 (Hammerschmidt).

Methanol Vapor Loss Factor (K_v)

Worked 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)

Practical Concentration Limits & Suppression

Maximum practical inhibitor concentrations in the aqueous phase and representative suppression at 25 wt % (universal K = 2335 basis):

6. MEG (Glycol) Injection Rate Sizing

Glycols are preferred for pipelines because they are regenerable with minimal vapor losses. The lean glycol injection rate is set by the water rate and the difference between lean (injected) and rich (spent) concentrations:

Rich glycol concentration (Hammerschmidt):
  C_rich = 100 × M × ΔT / (2335 + M × ΔT)

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)

Worked Example — MEG Injection Rate

Given: 100 bbl/day water, need 25 °F suppression
       Lean MEG = 85 wt %, M = 62.07, K = 2335

Rich MEG concentration (Hammerschmidt):
  C_rich = 100 × 62.07 × 25 / (2335 + 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)

See Section 3 for the full MeOH-vs-MEG selection trade-off (recoverability, vapor losses, CAPEX vs OPEX).

7. Corrosion Inhibitor Dosing

Inhibitor injection skids on wet-gas and produced-water systems often dose a film-forming corrosion inhibitor alongside the hydrate inhibitor. Film-forming corrosion inhibitors protect against CO₂ and H₂S attack; dosing is typically ppm-based on produced water volume.

Typical Dosing Rates

Injection Rate Calculation

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 × 10^6) = 0.12 gal/day

8. 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.
• NACE SP0106 — Control of Internal Corrosion in Steel Pipelines and Piping Systems.
• API RP 14E — Design and Installation of Offshore Production Platform Piping Systems.