Oil-Soluble LDHI Represents New Breed of Hydrate Inhibitor

Natural-gas hydrates may stand alone among oil and gas production problems in both the rapidity with which a severe problem can develop and the potentially catastrophic safety, environmental, and financial risks raised by worst-case scenarios.

Unlike corrosion or scale or paraffin buildup, which typically take months or years to evolve into production problems, gas-hydrate plugs have been known to form in subsea flowlines and pipelines in an hour or less. Fig. 1 depicts a gas-hydrate plug that has been removed from a production line by means of pigging. Once a hydrate plug has formed, it can take weeks or even months to dissociate it safely. Meanwhile, downtime and production losses mount day by day, and this impact can be huge, compared with other production problems.

Fig. 1—A gas-hydrate plug taken from an offshore production line is shown as it is removed from a pig launcher after a pigging operation.

Gas hydrates are ice-like crystals composed of water and natural gas, in which methane or carbon dioxide has become trapped in hydrogen-bonded cages. Unlike ice formed from H2O, though, gas hydrates are quite flammable and explosive. A cubic foot of gas hydrate at standard conditions contains 0.8 ft3 of water and 182 ft3 of methane. The hydrate plug can explode with a huge destructive force that may rupture subsea flowlines, damage production equipment, place workers at high risk, and endanger the ocean environment. Given these risks and the difficulty of remediating gas-hydrate plugging, most operators view prevention as their only real strategy for dealing with the problem.

Hydrate Conditions in Deep Water

Hydrates are formed thermodynamically whenever natural gas and water are present in the right combinations of low temperature and high pressure. Unlike pure ice, hydrates can form at temperatures much greater than 32 degrees Fahrenheit (°F). Hydrates have been shown to form in gas/water mixtures at temperatures of 40°F with pressure as low as 166 psi. It has been demonstrated, furthermore, that if pressures are great enough, hydrates can form in some gas/water compositions at temperatures as warm as 80°F.

The extreme temperature and pressure regimes encountered on the world’s ultradeepwater exploration and development frontiers combine to create almost perfect conditions for hydrate creation. In thousands of feet of water with long subsea tiebacks, production cools rapidly as it travels through flowlines from the well to the producing facility. The farther the flowstream travels, the more it is cooled by the surrounding seawater and the greater its risk of gas-hydrate formation somewhere within the production system.

Hydrate-Inhibition Strategies

Conventional hydrate-prevention and -inhibition strategies can be organized into the following approaches:

Changing the temperature and/or pressure conditions within the production system to reduce the potential of hydrate plug formation.
Separating production-stream gases and liquids subsea as close to the wellhead as possible, so that water and gas are not in contact when production-stream temperatures and pressures are conducive to hydrate formation.
Injecting thermodynamic, kinetic, or antiagglomerate (AA) chemicals into the production stream to inhibit hydrate formation.

To change temperature conditions within the production system, operators may insulate flowlines and/or equipment or, before a startup or resumption of production flow, circulate hot oil through production facilities to warm them. To change pressure conditions, operators may blow down the flowlines to reduce pressure levels until they are below the hydrate-formation range. However, all of these options significantly increase either capital or operating costs or both.

Similarly, separating production fluids and gases subsea, although effective, is capital intensive. In addition, competition for limited subsea processing space is keen, and subsea processing technologies in general are still in an early stage of development, so unexpected problems could emerge.

Pros and Cons of Chemical Inhibitors

The oldest and most widely used chemical hydrate preventatives are thermodynamic inhibitors such as methanol and glycols. Producers like thermodynamic inhibitors because of their usage from a long time and as they also used for other operational activities.

However, treating hydrates often requires large volumes of thermodynamic chemicals. Treatment concentrations can range to a 30% ratio of glycol to water. With methanol, concentrations are frequently set in the 30–50% range, and in flow systems with potentially severe hydrate problems, concentrations can approach 100%. Methanol is also flammable and not only carries dissolved oxygen that can lead to corrosion but can cause salt to precipitate into the production system. In addition, refiners impose fines for crude treated with methanol because of the risk that residual methanol poses to processing catalysts.

Kinetic hydrate inhibitors (KHIs) are polymers that prevent or delay nucleation and crystallization of hydrates in flowlines and production piping. They are effective at lower concentrations (0.5–3.0%) than the thermodynamic chemicals and along with the AA chemicals are typically, although not always, classed as low-dosage hydrate inhibitors (LDHIs). KHIs are capable of handling only low-to-moderate subcooling of 10–25ºF. Subcooling is the difference between the system operating temperature and the temperature at which hydrates would form at the same operating pressure. Because of their limitations in subcooled environments, KHIs are not suitable for all hydrate conditions—especially in the deep and ultradeep waters of the Gulf of Mexico, where subcooling greater than 30ºF is the norm. Furthermore, KHIs can provide protection only for hours rather than days, weeks, or months, which poses problems when systems are shut down for any length of time. Some KHIs also are incompatible with corrosion inhibitors.

Compared with the thermodynamic and kinetic inhibitors, the antiagglomerate LDHI chemicals possess a number of potential advantages. However, they impose certain requirements and in some cases have restricting factors. Fig. 2 presents a cost comparison, per barrel of water produced, between the use of methanol and an AA inhibitor, based on typical concentrations of 30 vol% for methanol and 1 vol% for the AA LDHI. The cost per gallon used in these calculations for methanol and LDHI are USD 2.50 and 20, respectively. It is obvious from the calculations that an operator could save hundreds of thousands of dollars by switching from methanol to LDHI. In addition to comparative costs, consideration should be given to the impact of relative storage requirements for the two chemicals on limited offshore processing space.

Fig. 2—A cost comparison between methanol and a new-generation AA LDHI based on the volume of produced water.

Compared with KHIs, conventional AA chemicals are generally more cost-effective and, unlike KHIs, retain their effectiveness in extreme subcooling conditions. Thus, AA inhibitors are capable of preventing the formation of hydrate plugs in all subsea temperature conditions encountered in the Gulf of Mexico. AAs also are effective at relatively low dosage rates (0.5–1.5 wt% of water phase) and retain their effectiveness for long periods.

However, AAs need a hydrocarbon phase to disperse hydrate crystals in the production stream. In addition, old-generation AAs are incompatible with some production-system materials, processing fluids, and production chemicals. AA chemical volumes and treatment rates must be increased as water production increases over the lifespan of a producing asset. Perhaps most important, old-generation AAs are water-soluble and consequently can have some serious environmental issues. For example, they can destabilize asphaltenes, requiring additional chemical cost to prevent asphaltene deposits in the production system and produced water. Otherwise, there can be problems meeting water-disposal requirements at remote, deepwater wellsites.

New ‘Green’ AA Molecule

Recently, a new, “green,” oil-soluble AA molecule has been developed that resolves many shortcomings of the conventional AA LDHI chemistries. It is the only oil-soluble molecule among the AAs or KHIs. This new molecule in turn has led to formulation of hydrate-prevention chemistries that can remain effective in production streams with water cuts as great as 90% and have been shown to inhibit hydrate formation in subcooling as great as 50°F. Effective treatment rates of the new AA chemistries are approximately half those of comparable conventional AA treatments (0.5 to 1.5% vs. 1.0 to 3.0%, respectively), which can reduce treatment costs significantly.

Unlike old-generation AAs, the new AA molecule is fully compatible with all seal, O-ring, and/or valve materials that are compatible with methanol. This allows producers to convert to the new chemistry without shutting in production to upgrade facilities. The new AA chemistry also does not destabilize asphaltenes.

Additionally, in tests by an independent environmental laboratory, the new AA chemistry was shown to have as little as one-tenth the toxicity level set by the U.S. Environmental Protection Agency in its No Observed Effect Concentration standard for Gulf of Mexico locations.

When designed for a specific application, the new green AA chemistries have been proved to reduce hydrate-inhibition costs significantly, while expanding the range of effectiveness to encompass the temperature and pressure regimes encountered in deep and ultradeep water.

The oil solubility of the new AA molecule adds a dimension of environmental protection that was impossible to achieve with older AAs. This means the new AA chemistries are suitable for use in the world’s most demanding and environmentally sensitive deepwater frontiers.

Information provided by Rama Alapati, Engineering Team Leader, Technical Support & Development, and Ann Davis, Section Manager—Flow Management Team, Champion Technologies.