Top Energy Training

Hydrate and Wax

In pipeline systems, different types of solids may form, agglomerate, precipitate or deposit on pipe wall, which can reduce the flowing area or block the pipeline.  These solids can be gas hydrate, wax (or paraffins), asphaltene, scales, etc. In this section, we will mainly discuss gas hydrate and wax.

Gas hydrates

Gas hydrate is a white, solid, ice-like substance that forms at temperatures above the water-freezing temperature at elevated pressures. The picture below shows a burning gas hydrate and gas hydrate pigged from a pipeline.

A burning gas hydrate
Gas hydrate pigged from a pipeline

Gas hydrate consists of approximately 90 wt% water and 10 wt% nature gas.  Microscopically, gas hydrate is composed of a water cage formed by water molecules, and a guest molecule inside the cage (see Figure 1 below).  The guest molecule is light natural gas components, such as CH4, C2H6, C3H8, i-C4H10, CO2, or H2S. 

Figure 1. Gas hydrate structure

Gas hydrate can present in three types of structure. Structure I consists of both 12-sided small cage and a 14-sided larger cage, with 36 water molecules and light gas compounds such as CH4, C2H6, and CO2.  Some water cages may not encompass natural gas compounds.  This type of gas hydrate primarily exists in nature rather than pipeline systems.  Structure II structure consists of both a 12-sided small cage and a 16-sided larger cage of 136 water molecules and heavier natural gas compounds such as C3H8 and i-C4H10. This type of gas hydrate is the most commonly encountered one in most natural gas and oil production systems.  Structure H consists of small, medium, and large cages of 34 water molecules, and are seldom found in artificial or in natural processes. 

Figure 2 below shows the pressure-temperature (P-T) phase diagram for methane hydrate.  The hydrate dissociation or hydrate equilibrium curve represents the thermodynamic conditions for a hydrate to be dissociated. A hydrate requires several degrees of subcooling (temperature difference between the dissociation temperature and the fluid temperature at the same pressure) before it will actually form at the conditions of the hydrate formation curve, and this subcooling is shown as the dashed line in the figure.  The region between the hydrate dissociation curve and the hydrate formation curve is called metastable region.  When the temperature is below the water freezing curve, both hydrate and ice form, making it more difficult to remediate.

Figure 2. P-T phase diagram for methane hydrate

Gas hydrate formation and blockage can happen very fast if untreated, making it one of the top risks that require significant attention during pipeline operation, especially for offshore pipelines.  Gas hydrate formation does not cause pipeline blockage if they do not deposit on the pipe wall or agglomerate.  Gas hydrate needs to undergo several processes before causing pipeline blockage, including hydrate nucleation (formation), agglomeration, deposition or growth, and blockage, as explained in Figure 3.  

Figure 3. Conceptual picture of hydrate formation in oil-dominated system

To prevent gas hydrate blockage, the following three ways are suggested:

  • Eliminating one of the three requirements for hydrate formation by either depressurizing the pipeline, dehydrating the natural gas by removing the water phase, or maintaining the thermal energy by heating or insulation.
  • Shifting the gas hydrate dissociation curve to the left by injecting a thermodynamic hydrate inhibitor (THI) to shrink the hydrate region in the P-T phase diagram.  The two typical THI are methanol (MeOH) and monoethylene glycol (MEG).  MEG is less toxic than MeOH and can easily be regenerated. However, it may clog with salt precipitated from water, resulting in high operating and maintenance costs.
  • Managing hydrate by preventing gas hydrate agglomeration and growth by injecting a low-dosage hydrate inhibitor. This type of method is cost-effective and more practical than preventing gas hydrate formation.  The two main inhibitors of this type are kinetic hydrate inhibitors (KHI) which prevent hydrate growth, and antiagglomerants (AA) which prevent hydrate particles from sticking together (or agglomerating). Please note that these two types of inhibitors do not prevent hydrate nucleation.

When the blockage occurs, the following four methods can be applied:

  • Pressure reduction. When the pressure is reduced below the hydrate dissociation curve, the hydrate will dissociate.  It is crucial to mention that two-sided depressurizing should be performed instead of one-sided to eliminate the risk of pipeline or components failure due to the fast movement of hydrate plugs.
  • Chemical injection. However, this method is difficult if the blockage is far from injection locations.
  • Mechanical removal.  Pigging can be used to remove hydrate if it is soft and only partially bridge the pipe.
  • Thermal application. Heating is another way to remove hydrate blockage by increasing the temperature above the hydrate dissociation temperature.  It is also important to mention that uniform heating is necessary to prevent local pressure buildup induced by partial dissolution.  When gas is released from hydrate, it increases the pressure if it is trapped between hydrate plugs, which can post a danger of pipeline burst.


Wax (paraffin) is a heavy organic constituent primarily comprising high-molecular-weight paraffinic compounds that are crystalline in nature and range from C20 to C90. There are two types of wax compounds: normal and isoparaffin chains made of C18 to C36, and naphthenic paraffin chains of C30+.  Normal paraffin often occurs in production and transportation of crude-oil systems, while naphthenic paraffin is mainly encountered in tank-bottom sludges. The two necessary conditions for wax deposition in the pipeline are:

Wax in pipeline

The fluid temperature must be below the wax appearance temperature (WAT)

Temperature decreases in the radial direction from the center of the pipe to the pipe wall caused by the cold surrounding environment.

When wax deposition occurs, it reduces the flowing area, increasing the pressure drop and decreasing the flow rate. However, the wax deposition process is much slower as compared with gas hydrate.  In most cases, wax deposition is not prevented due to the high cost, but is removed periodically using pigging (Figure 4). There are different types of commercialized “pigs” used for cleaning, such as disk, cup, bypass, sphere, and foam, that are designed for different flow and deposition conditions (Figure 5).

Figure 5. Pictures of some commercialized pigs