Preventing formation of hydrate plugs

The prevention of hydrate-plug formation and safe removal of hydrate plugs represent 70% of deepwater flow-assurance challenges; the remaining 30% deal with waxes, scale, corrosion, and asphaltenes. Before considering prevention of hydrate plugs, it is important to consider safety problems involving hydrate plug removal.

Hydrate formation

What is a typical pressure at which hydrates will form? Hydrate-formation data, at a typical deep seafloor temperature of 39°F, were averaged for 20 natural gases (listed in Chap. 6 of Ref. 1) with an average formation pressure of 181 psia. Of the 20 gases, the lowest hydrate-formation pressure was 100 psig for a gas with 7 mol% propane, while the highest value was 300 psig for a gas with 1.8 mol% propane. Because systems usually operate at much higher pressures than 181 psia to obtain an economic energy density, hydrates are a possibility whenever small (n-butane or smaller) hydrocarbons come into contact with water.

In Predicting hydrate formation, a hand calculation method, accurate to 75%, is given for hydrate formation.

Prevention methods

There are four techniques to prevent hydrate formation:

• Remove the free and dissolved water from the system with separators, glycol dehydrators, molecular sieves, or other methods
• Maintain high temperatures so that hydrates do not form
• Maintain low pressures to keep all phases fluid
• Inject an inhibitor to prevent hydrate formation

The first of these methods of prevention is the most reliable. It may not be viable, however, to remove water because of remote locations, submersion, or other factors. For these reasons, flow channels are frequently operated with inhibitor injection at the well, followed by dehydration at a downstream point. The prediction accuracy of hydrate formation (for the second and third prevention techniques) is acceptable for the energy industry, within 10% pressure for well-defined fluids at temperatures greater than 32°F and pressures below 5,000 psig. In the fourth method, predictions can also indicate the free-water concentration of thermodynamic inhibitors, such as methanol (MeOH), monoethylene glycol (MEG), or salts (in drilling fluids), which are injected to compete with the hydrate structure for water molecules.

A hand calculation method for inhibitor concentration in the free-water phase is discussed later in the chapter. Remember that inhibitors are also in small, but significant, concentrations in vapor and liquid hydrocarbon phases. Because the total-flow fractions of these latter two phases are so large, much of the injected inhibitor is consumed in the vapor and liquid hydrocarbon phases. Inhibitor partitioning is also summarized with hydrate inhibition in Example 1.

Example 1: hydrate formation in a pipeline

Notz provided a case study of hydrate formation, shown in Fig. 1, for a Gulf of Mexico pipeline fluid. To the right of the diagram, hydrates will not form, and the system will exist in the fluid (hydrocarbon and water) region. However, hydrates will form in the region at the left of the line marked “Hydrate-Formation Curve,” and hydrate-prevention measures should be taken.

• 

  Fig. 1—Case study of hydrate formation in a gulf of Mexico pipeline fluid(after Notz et al.

Pipeline pressure and temperature conditions were predicted using a pipeline prediction program such as OLGA® or PIPEPHASE®, and those conditions are shown as the almost horizontal line, superimposed on the hydrate conditions in Fig. 1. At small pipeline distances (e.g., 7 miles) from the subsea wellhead, the flowing stream still retains some reservoir heat so that no hydrate forms. The ocean cools the flowing stream, and, at about 9 miles, a unit mass of flowing gas and associated water enters the hydrate region to the left of the hydrate-formation curve, remaining in the uninhibited hydrate area until 45 miles. Such a distance may represent several days of residence time for the water phase, so that hydrates would undoubtedly form, if inhibition steps were not taken.

In Fig. 1, by 25 miles, the temperature of the pipeline system is within a few degrees of the ocean-floor temperature, so that approximately 23 wt% methanol is required in the freewater phase to prevent hydrate formation and pipeline blockage. Methanol-injection facilities are not available at the needed points (9 through 45 miles) along the pipeline. Instead, methanol is injected into the pipeline at the subsea wellhead. In the case of the pipeline, shown in Fig. 1, sufficient methanol is injected at the wellhead so that an excess of 23 wt% methanol will be present in the free-water phase over the entire pipeline length.

As vaporized methanol flows along the pipeline in Fig. 1, it dissolves into any produced water or water condensed from the gas. Hydrate inhibition occurs in the free water, usually at accumulations where there is a change in flow geometry (e.g., a bend or pipeline dip along an ocean-floor depression) or some nucleation site (e.g., sand or weld slag).

Hydrate inhibition occurs in the aqueous liquid, rather than in the bulk vapor or oil/condensate. While most of the methanol dissolves in the water, a significant amount of methanol either remains with the vapor or dissolves into the liquid hydrocarbon phase. Even though the concentration of methanol in the vapor or liquid hydrocarbon is small, with low water amounts, the majority of methanol may be consumed by the vapor or liquid hydrocarbons because the hydrocarbon-phase fractions are much larger than the water-phase fraction.

In Fig. 1, Notz showed that the gas temperature increases from 30 to 45 miles with warmer (shallower) water conditions. From 45 to 50 miles, however, a second cooling trend is observed because of the Joule-Thomson gas-expansion effect. Methanol exiting the pipeline in the vapor, aqueous, and condensate phases is usually counted as a loss because of the expense of regeneration. However, a few companies are considering methanol recovery from the aqueous phase.

Drilling fluids and drillstrings

Hydrates can plug drillstrings, blowout preventers, chokes, and other equipment, sometimes requiring the abandonment of drilling operations because of safety constraints. Water-based drilling fluids are particularly susceptible to hydrate formation. The most important variable affecting hydrate formation is the activity of the water, which is decreased by chemicals that dissolve by bonding to water molecules. Water hydrogen bonds with alcohols or glycols or forms very strong coulombic bonds with salt ions. These bonds effectively compete with water hydrate bonds and prevent hydrate formation until much lower temperatures are reached, in the same way that, in winter, ice is prevented by the addition of antifreeze (glycol) to a car radiator.

It is important to recognize that other nonsoluble drilling-fluid components (e.g., mud solid particles or fluidizers) may affect the kinetics or rate of hydrate formation to determine how rapidly hydrates will form or decompose. However, the hydrate-formation temperature and pressure conditions are determined by water-molecule availability, as impacted by the water-soluble components. An interesting example of a kinetically inhibited drilling fluid was recently proposed by the use of lecithin, which prevented hydrate dissociation in an Arctic hydrate well application.9 See the discussion on kinetic inhibition.

Technologies for hydrate-plug prevention

With the state-of-the-art methods of hydrate prevention, we turn to hydrate-plug prevention technology. In addition to the conventional inhibitors MeOH and monoethylene glycol (MEG), there are three new types of hydrate inhibitors, sometimes called low-dosage hydrate inhibitors, which were tested in the field during the 1990s. However, even with the low inhibitor concentrations, for long tiebacks between wellheads and platforms, chemicals typically represent the most expensive flow-assurance solution. Slurry flow and heating/insulation represent, respectively, the fourth and fifth methods of hydrate prevention. A discussion of each method follows.

Deep ocean temperatures are fairly uniform at about 39°F, except for some anomalous deepwater current environments. Gulf of Mexico deepwater wellhead pressures represent some of the highest in the world, at 15,000 psia. Such a combination of low temperatures and high pressures provides high driving forces for hydrate formation. Hydrate-plug prevention requires a system that can withstand a substantial subcooling (ΔT = hydrate equilibrium temperature minus typical deepwater temperature of 40°F) of up to 35°F; high-pressure pipelines have high hydrate-equilibrium temperatures.

Dispersants or antiagglomerants

The object of these chemicals is to convert water into finely dispersed hydrate particles that can be transported in a hydrocarbon liquid. These chemicals are typified as long-chain quaternary ammonium salts, which easily form hydrates, replacing part of both the water and guest frameworks. While three of the four branches of a quaternary nitrogen salt form as a part of the hydrate structure, the fourth acts as a long tail that protrudes from the hydrate structure and prevents agglomeration of the hydrates into a larger mass. There must be substantial hydrocarbon liquid to disperse the hydrates; the maximum water volume is 40% of the total liquid phase.

The commercial use of dispersants began in the Gulf of Mexico in 2001, after laboratory studies showing ΔT = 45°F subcooling. These dispersants are particularly effective in hydrate-plug protection upon line shut-ins and restarts. However, more-extensive field testing should be done. As these inhibitors come into commercial use, environmental concerns for water purity will have to be resolved.

Kinetic inhibitors

These chemicals are polymers with carbon backbones and pendant groups, which adsorb into partially formed hydrate cages to keep the polymer anchored along the hydrate-crystal surface. Growing hydrate crystals are forced to grow around the polymer, stabilizing the hydrates as small particles in the aqueous phase. No liquid hydrocarbon need be present. Field tests have shown these chemicals to be effective at subcoolings up to ΔT = 20°F, at dosages from 550 to 3,000 ppm in the water phase. There is concern about these chemicals with respect to performance on shut-in and restart; also, a substantial amount of hydrate normally forms upon inhibitor failure.

Emulsifiers

These chemicals work by stabilizing small hydrate particles in an oil phase. Some oils contain natural emulsifiers such that, even with favorable hydrate formation conditions, the water, which might convert to hydrates, is stabilized within the oil phase. To date, efforts to identify the stabilizing components, remove them, and re-insert them in a noninhibited oil have been unsuccessful. Artificial emulsifiers have been shown to be effective, preventing hydrate plugs in flow loops. There are concerns about these chemicals regarding the expense of tailoring them for each oil application and the cost associated with emulsion breaking.

Slurry flow

This method uses the concept from Austvik : hydrates that form in the fluid phases will not adhere to the pipe wall. The ideal slurry system has the use of a subsea separator to remove the majority of produced water and subsequent rapid heat exchange to seafloor temperatures in the hydrate region, causing rapid hydrate formation as a liquid-phase slurry. It should be noted that subsea/downhole separation will help every hydrate-prevention scheme, by removal of most of the free-water fraction that forms hydrates.

A substantial industrial research effort is being spent on development of rapid techniques for hydrate-slurry formation in the fluid. Slurry tests of several proprietary systems have been sponsored by a consortium of energy companies. While this method is the most economical of the hydrate-inhibition techniques, it is also the most ambiguous, in terms of likelihood of success. In particular, there is a concern about agglomeration of hydrate particles during shut-ins.

Insulation and heating

Because fluids come from the reservoir at high temperatures, a lowcost solution is to preserve the reservoir temperature (or add heat to the line) to keep the system out of the hydrate region. There are three types of insulation listed in ascending order of cost: coatings applied to pipes; pipe-in-pipe (PIP) or bundling; and vacuum-insulated pipes or pipes with insulating gases. Of the three types, the last is so expensive that it is not in commercial use, and with the PIP method, the repair of leaks is a concern. If a bare pipe is considered as the baseline cost, insulation can easily double to quadruple the installed-pipe cost. At the 2000 SPE Flow Assurance Forum, it was estimated that insulation was less efficient than expected approximately 50% of the time. For example, a recent Gulf of Mexico flowline experienced an overall-heat-transfer coefficient of 2 Btu/(hr-ft²-°F), while the design coefficient was 0.176 Btu/(hr-ft²-°F), the latter being a typical value for such applications.

In combination with insulation, line heating may be done through resistance or induction heating, with practice favoring the former. Heating costs are very high, second only to chemical treatment, and the power for heating is generated on platforms, where typically only 5 to 10 MW may be available. There is evidence that short lines (< 20 miles) can be handled with heat management; however, heating solutions may not be practical at line lengths greater than 50 miles.

Noteworthy papers in OnePetro

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External links

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See also

Hydrate plug removal

Hydrate problems in production

Transporting stranded gas as hydrates

PEH:Hydrate_Emerging_Technologies