Hydrate problems in production

Natural-gas hydrates are ice-like solids that form when free water and natural gas combine at high pressure and low temperature. This can occur in gas and gas/condensate wells, as well as in oil wells. Location and intensity of hydrate accumulations in a well vary and depend on:

• Operating regime
• Design
• Geothermal gradient in the well
• Fluid composition
• Other factors

Detailed reviews of gas-hydrate chemistry, physics, and oilfield engineering are found in Makogon and Sloan. This page focuses on prevention, inhibition, and removal of hydrates in production. Other pages provide more detail on hydrate formation and predicting hydrate formation.

Special situations

Shut-in gas wells are particularly prone to serious hydrate problems, if the well has been producing some water. Subsequent equilibration of the tubular and its contents with cold zones of the rock can lower the temperature into the hydrate-formation region. Hydrate nuclei form from the films of water on the tubular walls. The subsequent crystallization can result in large plugs of hydrate tens or hundreds of meters long.

Hydrate formation also can take place within a shut-in oil well, generating a slurry of solid that is capable of accumulating and plugging the pipe. The logic is that oil will dissolve some water—generally small amounts. Under high-temperature/high-pressure (HT/HP) conditions, the amounts can be 5 to 10 mol% (at 300°F). The oil is produced up the wellbore, temperature falls, and liquid water comes out of solution, remaining in suspension as microdroplets. In a static condition, the microdroplets gradually coalesce and precipitate. This liquid water is saturated with gas so that hydrates can form at the appropriate pressure/volume/temperature (PT) values.

Controlling hydrate formation

The first step in controlling hydrate formation is to understand which pressure and temperature conditions/locations in the specific system are conducive to gas hydrate formation. A number of computer simulators are available for this purpose, usually as adjuncts to more general phase PVT simulators. The models vary in how well they compute the chemical activity of the water phase, the effect of higher-molecular-weight hydrocarbons, and the effect of hydrate inhibitors (see the discussion that follows). A comparative assessment of models is given in Sawyer. Fig. 1 shows the results of simulations with one of the models—the line is computed, the dots are experimental points. Besides the dissociation PT points for the hydrate, the information required and derivable from such models is the amount of hydrate formed, the composition of all phases, and the distribution of inhibitors throughout all phases.

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  Fig. 1—Simulated and experimental gas hydrate equilibrium diagram for a natural-gas mixture (points are experimental).

The second control step is the comparison of this information with the measured or expected PT profile within the production system. A method of coping with hydrate formation is then selected (e.g., producing the hydrocarbons under conditions that avoid the hydrate PT formation zone or using a suitable inhibition method. The simulator should also be capable of evaluating the consequences of the inhibitor strategy. An example of adjusting production conditions to avoid hydrate formation is PT curves for producing wet gas at various rates.

Inhibitors

The alternative to production control is the use of inhibitors. These are classified as:

• Environmental inhibitors
• Thermodynamic inhibitors
• Kinetic inhibitors

The conceptually simplest “environmental inhibition” method is to dry the gas before it is cooled—remove the water and hydrates so they cannot form. This involves adsorption onto, for example, silica gel, or cooling and condensation, absorption of water into alcohols, or adsorption onto hydroscopic salts.

“Thermodynamic inhibition” has been the most common method for controlling gas hydrates. There are a number of alternatives:

• Heating the gas
• Decreasing pressure in the system
• Injecting salt solutions
• Injecting alcohol or glycol

One method of providing heat to the hydrate-formation zone is the use of electrical-resistance heating via cables connected to a transformer. Another is placing the choke in a sufficiently hot zone of the production system. The injection of salts (primarily CaCl₂) reduces hydrate formation by lowering the chemical activity of water, and by lowering the solubility of gas in water.

The last alternative is used more frequently now with a transition from methanol to ethylene glycols for health, safety, and environment (HSE) reasons. The general effect of such inhibitors is shown in Fig. 2 (not a total removal of the problem but a shift of the hydrate-formation curve to lower temperatures, ostensibly outside the PT production regime). It is possible to compute this phase diagram for gas/water/methanol or the glycols with reasonable accuracy. The major drawback to this inhibition technique is the large quantity of methanol or glycol required. This impacts both operating costs and logistics, particularly important for offshore wells and pipelines.

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  Fig. 2—A general phase diagram illustrating the effect of inhibitors on hydrate prevention.

Such problems have resulted in the search for kinetic hydrate inhibitors —low-dosage chemicals that prevent the growth of hydrate nuclei or prevent the agglomeration of nuclei into large crystals (also called “threshold hydrate inhibitors”). Klomp, et al. describes the field testing of such inhibitors. The compounds were primarily quaternary ammonium salts; polymeric n-vinyl-2-pyrrolidone was particularly effective. The application of kinetic hydrate inhibitors to black-oil flowlines is described in Pakulski, et al. The additive here was a methanol-based solution of the polymer n-vinyl, n-methyl acetamide-covinyl caprolactam (“VIMA-VCap”). In the example given, the dose rate was low (0.5 gal/D in 16 B/D of produced water). Nonpolymeric gas hydrate inhibitors have been successfully field tested on an offshore platform containing gas lift injection wells, and they have been used in long wet-gas subsea pipelines. A novel gas hydrate inhibitor controlling hydrate formation during startup uses a borate-crosslinked gel system; this inhibited gel system ostensibly also exhibits fracturing-fluid performance equal to that of more conventional borate-gel systems.

Removal of solid hydrates

Solid hydrates are removed with many of the same chemicals and technology used to inhibit hydrate formation. The simplest method is, if possible, to reduce pressure above the hydrate plug sufficiently enough to reverse the equilibrium reaction. Addition of solvents, such as alcohols and glycols, is the most common technique (well completions will often provide for a methanol-injection line). An example of hydrate-plug removal with coiled-tubing jetting from a deepwater test well is given in Reyma and Stewars. Chemical heating, such as described for wax removal, has been used. See also hydrate plug removal

Noteworthy papers in OnePetro

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External links

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See also

Predicting hydrate formation

Preventing formation of hydrate plugs

Hydrate plug removal

Equilibrium of water and hydrocarbon systems with hydrates

PEH:Well_Production_Problems