Methanol & MEG Injection for Hydrate Prevention

The Hydrate Threat in Wet Gas Systems

In offshore subsea pipelines or remote winter gathering lines, raw natural gas flows completely saturated with water. The extremely low ambient temperatures (e.g., 4°C / 39°F at the seabed) combined with high pipeline pressures create the perfect thermodynamic environment for Gas Hydrates.

Hydrates are solid ice-like crystals where water molecules form a cage trapping a methane molecule. They will rapidly stick together to form massive, concrete-hard plugs that can completely block a pipeline. Because you cannot economically install a massive TEG dehydration plant at every single subsea wellhead, engineers must inject specialty chemicals directly into the wet pipeline to prevent hydrates from forming during transit to the main processing plant.

Thermodynamic Hydrate Inhibitors (THI)

Just as you put antifreeze in a car's radiator to lower the freezing point of the coolant, process engineers inject antifreeze into pipelines. These chemicals aggressively hydrogen-bond with the liquid water molecules, disrupting their ability to form crystalline hydrate cages, thereby drastically suppressing the temperature at which hydrates can form.

The two dominant THIs used globally are Methanol ($CH_3OH$) and Monoethylene Glycol (MEG).

Methanol Injection

Methanol is a cheap, simple alcohol with a very low viscosity, making it easy to pump through long, tiny umbilical lines to subsea wellheads.

• Pros: Excellent for severe temperature suppression (it can suppress hydrate formation down to -50°C). It acts extremely fast, making it the universally preferred chemical for intermittent injection (e.g., during startups, shutdowns, or sudden winter cold snaps).
• Cons: Methanol is highly volatile. When injected into a gas pipeline, a massive percentage of the methanol vaporizes into the gas phase. Vaporized methanol does absolutely nothing to inhibit the liquid water on the bottom of the pipe. Therefore, you must inject massive quantities to ensure enough remains in the liquid phase. Furthermore, it is a "use once and lose it" chemical—it cannot be economically recovered and regenerated. Downstream refineries also heavily penalize crude oil or condensate shipments that are contaminated with methanol.

MEG (Monoethylene Glycol) Injection

MEG is the industry standard for continuous, high-volume, long-distance subsea pipelines.

• Pros: MEG has very low volatility. Almost 100% of the injected MEG stays directly in the liquid water phase where it is needed. At the receiving onshore plant, the MEG-Water mixture is separated from the gas and sent to a massive MEG Regeneration Unit (MRU). The water is boiled off, and the MEG is continuously recycled back to the offshore platform.
• Cons: MEG is highly viscous at low temperatures, making it difficult to pump through long subsea umbilicals. It cannot suppress hydrate temperatures as deeply as methanol. The onshore regeneration units are massive, expensive capital investments, and because the produced water contains reservoir salts, the boiling process often leads to severe salt precipitation and fouling in the MRU.

The Hammerschmidt Equation

To calculate exactly how much THI to inject, engineers historically used the Hammerschmidt equation (though modern EOS software like HYSYS is now standard):

$$ \Delta T = \frac{K \cdot W}{100 - W} $$

Where:

• $\Delta T$ = Required hydrate temperature depression (°F)
• $K$ = Thermodynamic constant (2335 for Methanol, 4000 for MEG in Imperial units)
• $W$ = Weight percent of the inhibitor required in the free water phase

Try the Calculator

When injecting massive amounts of MEG into a pipeline, the flow transitions into a complex two-phase (gas-liquid) regime. Ensure your pipelines are properly sized to handle this additional liquid loading and increased frictional pressure drop using the Gas Line Calculator on this page.