Hydrate/Wax/Asphalt in Subsea Pipeline

1. Hydrate in subsea pipeline

Natural gas hydrates are solid crystalline compounds of snow appearance with densities smaller than that of ice. Natural gas hydrates are formed when natural gas components, for instance methane, ethane, propane, isobutene, hydrogen sulfide, carbon dioxide, and nitrogen, occupy empty lattice positions in the water structure. In this case, it seems like water solidifying at temperatures considerably higher than the freezing point of water.

Hydrate in pipeline
Source: http://www.ipt.ntnu.no/~jsg/undervisning/naturgass/oppgaver/Oppgaver2014/14Gama.pdf

Hydrates particles set a problem :
  • The flowing driving force is the differential pressure between the well head and the production facilities area. So the occurrence of gas hydrate phase acts as a decrease of this driving force because particles consume the lighter components and decrease the pressure.
  • The viscosity of the fluid increases and so the flow rate decreases which is prejudicial to the productivity of the well.
  • Finally, one has to separated the hydrate phase (solid phase) from the rest of the liquid before it enters in the classical separation apparatus.
The gas hydrate crystallization in pipeline is first appeared in artic area because the temperature is so low that a low pressure is enough to stabilize the hydrate phase. Such a context occurs in arctic area but in Siberia and south of Argentina too. As the oil exists to the well head, it is at a high temperature corresponding to the temperature of the sediment in which the well has been drilled. But, as the flow moves along the pipe, its temperature decreases because of the low temperature of the wall. Finally, the oil is at the same temperature as the surrounding and the gas hydrate crystallization becomes possible.The temperature is not low, but the pressure can be very high and sufficient to stabilize the hydrate phase.

Risk of hydrate plugging
Source: http://www.emse.fr/fr/transfert/spin/depscientifiques/GENERIC/hydrates/introduction/pipeplug.gif

Different remedies have been envisaged :
  • The first one consists in insulating the pipeline in order to maintain the oil at a constant temperature equal to the temperature at the exit temperature at the well head which is sufficiently high. The cost is very high but it can be envisaged for the biggest oil pipes which collect the flow of different wells.
  • The second solution consists in shifting the equilibrium temperature of gas hydrate in order to make impossible the crystallization. This is possible by injecting thermodynamical additives which modify the water properties. Such components are alcohols such as glycohols, or salts. But for very deep wells, this solution is not reasonable because of the quantity of additives to inject, sometimes 50% in mass of the total water flow contained in the oil flow.
  • The third solution consists in using dispersants which will allow to transport the hydrate phase without agglomeration and without plugging. But one has to construct equipment for the separation of the hydrate phase from the rest of the liquid.
  • The last solution consist in using a new class of inhibitors called kinetic additives. These components do not affect the thermodynamical properties of water because they are added in very low quantities, not more than 1% in mass of the total water flow. Their role is to act as crystallization inhibitors by decreasing the rate of processes such as nucleation, growth and agglomeration. The crystallization becomes so low that it is impossible to observe it during the time range of the transport in the pipeline. 
 2. Wax/paraffin in subsea pipeline

Waxes are typically long, linear or branched n-paraffin chains within produced hydrocarbons and primarily consist of paraffin hydrocarbons (C18 - C36) and naphthenic hydrocarbons (C30 - C60).
Hydrocarbon components of wax can exist in various states of matter (gas, liquid or solid) depending on their temperature and pressure. When the wax freezes, it forms crystals referred to as macrocrystalline wax. Those formed from naphthenes are known as microcrystalline wax. The solid forms of paraffin, called paraffin wax, are from the heaviest molecules from phytane (C20H42) to lycopane (C40H82).

As the temperature of the crude drops below a critical level and/or as the low-molecular-weight hydrocarbons vaporize, the dissolved waxes begin to form insoluble crystals. The deposition process involves two distinct stages: nucleation and growth. Nucleation is the forming of paraffin clusters of a critical size (“nuclei”) that are stable in the hydrocarbon fluid. This insoluble wax itself tends to disperse in the crude.

Wax in pipeline
Source: http://www.halliburton.com/public/multichem/contents/Overview/images/Paraffin-Deposits.gif

Wax deposition onto the production system (“growth”) generally requires a “nucleating agent,” such as asphaltenes and inorganic solids. The wax deposits vary in consistency from a soft mush to a hard, brittle material. Paraffin deposits will be harder, if longer-chain n-paraffins are present. Paraffin deposits can also contain:
  • Asphaltenes
  • Resins
  • Gums
  • Fine sand
  • Silt
  • Clays
  • Salt
  • Water
High-molecular-weight waxes tend to deposit in the higher-temperature sections of a well, while lower-molecular-weight fractions tend to deposit in lower-temperature regions. Prior to solidification, the solid wax crystals in the liquid oil change the flow properties from a Newtonian low viscosity fluid to a very-complex-flow behavior gel with a yield stress.

Paraffin deposition can cause a multitude of operational challenges including:
  • Reduction of the internal diameter of the pipelines, which restricts and can ultimately block flow.
  • Increased surface roughness on the pipe wall which causes increased back-pressure and reduced throughput.
  • Accumulations that fill process vessels and storage tanks, leading to system upsets and labor/OPEX-intensive cleanup and disposal problems.
  • Interference with valve and instrumentation operation.
  • Increased risk of sticking pigs in the line and interference with the in-line inspection of flowlines and export lines by tools such as gauge pigs, caliper pigs and intelligent pigs.
All of these problems may result in production shutdowns, hazardous conditions, and damage to equipment. Hence, it is important to study wax mitigation and remediation techniques.

The primary paraffin wax blockage remediation techniques common in the oil and gas industry are as follows:
  • Mechanical removal by using progressive pigging programs to remove accumulated deposits while ensuring that the use of an overly-aggressive pig will not result in the pig becoming stuck behind the wax accumulation.
  • The addition of heat to melt wax by the injection of hot oil, steam or hot water or the use of electrical heating to melt the wax deposits. When using this strategy it should be noted that the wax disappearance temperature (WDT) is typically higher than the WAT.
  • Usage of solvents and dispersants, such as diesel, xylene or kerosene to dissolve the deposit.
3. Asphalt in subsea pipeline 

Asphaltenes are a compound class, not a single compound, concentrated in the high-temperature distillation residue of petroleum (> 530°C). Other components are:
  • Heavy oils
  • Resins
  • High-molecular-weight waxes
Changes in pressure and temperatures may occur throughout the production process, causing existing asphaltenes to destabilize and precipitate, forming hard black deposits (asphalt) in pipelines. These solids can rapidly reduce production flow or produce plugs that completely block pipeline, shutting down production. The asphaltene content in the oil and the carbonate content in the water is relatively low, the deposition of these compounds in the well, the production tubing, the gathering system, the equipment of the treating plants, the storage tanks and the pipeline conveying the oil to the refinery causes considerable problems, such as:
  • reduction in the wells' production capacity;
  • partial plugging of the pipelines;
  • dirty equipment of the treating plants,
which, in turn, bring about significant economic effects (substantial reduction in the hydrocarbon recovery velocity, increase in production costs).

Asphaltene in pipeline
Source: https://media.licdn.com/mpr/mpr/shrinknp_400_400/AAEAAQAAAAAAAAQMAAAAJDFhMTk0YWI4LTllMjEtNDMyYS05ZmRlLWY5OGQ1M2NiN2E4OA.jpg

Removal of asphaltene deposits also requires the use of solvents or mechanical devices. However, the solvents used for asphaltene removal are quite different from those used for paraffins. Because asphaltenes are soluble in aromatic solvents, mixtures of aromatic solvents such as xylene have been used to remove asphaltene deposits. It should be noted that solvents such as diesel and kerosene that are primarily straight-chain alkanes should not be used because they may induce asphaltene precipitation.

Asphaltene deposits are generally removed manually, if present in readily accessible equipment, such as separators and other surface equipment. For tubular and flowline deposits, removal techniques involve chemical methods such as solvent soaks with or without dispersants. Combining solvents and heating may also be effective. Physical methods can be used depending on the hardness of the deposit (e.g., pigging, hydroblasting, and drilling). Pigging (cutting) is appropriate for removing pipeline deposits—often, mixtures of waxes and asphaltenes.



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