Gas production and transportation pose challenges for operators. Unprocessed gas streams in production and flow lines containing brine and hydrogen sulfide are particularly corrosive and susceptible to forming hydrates and scale deposits. Methanol is often added to such streams for hydrate prevention; however, methanol increases the corrosion tendencies of pipes and equipment because it can deactivate some Corrosion Inhibitors (CI) and adds oxygen to the system. As a result, if hydrates are controlled with methanol, the system requires extra amounts of properly selected corrosion inhibitors to counteract the oxygen induced accelerated corrosion.

Corrosion rates of tubular steel exposed to sweet and sour brines were investigated. The sweet conditions contained carbon dioxide saturated brine, methanol, corrosion and gas hydrate inhibitors. Hydrogen sulfide was added to the system to create a sour environment. Methanol and hydrogen sulfide present in wet gas streams create an environment difficult for corrosion control; they accelerate corrosion rates to the point of rendering some commercial corrosion inhibitors unsuitable for corrosion protection. It was discovered that some gas hydrate inhibitors offer both, hydrates and corrosion protection. In addition it was found that the corrosion inhibiting properties of these gas hydrate inhibitors were enhanced in the presence of hydrogen sulfide.

The dual action of the Low Dosage Hydrate Inhibitor (LDHI) described here can limit or even eliminate Corrosion Inhibitors in highly corrosive methanol containing sour gas/water streams; thus, LDHI application improves production and transportation economy by replacing high volumes of methanol with less costly volumes of LDHI and providing additional operational savings on CI.


Gas hydrates form when water molecules crystallize around guest molecules. The water/guest crystallization process has been recognized since its discovery by Sir Humphrey Davy in 1810 it is well characterized and occurs with sufficient combination of pressure and temperature.[1] Light hydrocarbons, methane-to-heptanes, nitrogen, carbon dioxide and hydrogen sulfide are the guest molecules of interest to the natural gas industry. Depending on the pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 30°C (∼85ºF).

Formation of undesired gas hydrates can be eliminated or hindered by several methods. The thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate forming gas, the presence of water, high pressure and low temperature. The elimination of any one of these four elements from the system would preclude the formation of hydrates. Heating and insulating transmission lines is a common mechanical solution to the hydrate problem often encountered in long subsea pipelines. Gas dehydration is another method of removing a hydrate component. However, in a practical oil and gas operation, water can be economically removed to a certain minimum vapor pressure only and residual water vapors are always present in a dry gas. Hydrate plugs in "dry" gas lines have been reported in the past.[2]

Tubular failures due to corrosion and pipelines plugging with solid hydrates are major concerns for gas production and transport operators. Hydrate plugs can form in a short time, often within a few hours at hydrate formation pressure and temperature (p/T) conditions. Corrosion is a significantly slower process taking months or years to manifest itself with hardware failing. Nevertheless, both processes can result in catastrophic consequences if left unchecked.

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