Gas hydrates are crystalline ice-like solids formed from water and a range of lower molecular weight molecules, typically methane, ethane, propane, hydrogen sulphide and carbon dioxide. The structures of the crystals fall into the class of clathrates with the water molecules forming a hydrogen-bonded cage-like structure which is stabilized by ‘guest’ molecules located within the lattice. To date there are three known hydrate structures referred to as structures I, II and H
Structure I hydrates: contain 46 water molecules per 8 gas molecules giving a hydrate number of 5.75. The water molecules form two small dodecahedral voids and six large tetradecahedral voids. The sizes of the voids are relatively small meaning that the guest molecules are restricted in size to essentially methane and ethane.
Structure II hydrates: contain 136 water molecules per 24 gas molecules giving a hydrate number of 5.67. The water molecules form 16 small dodecahedral voids and 8 large hexakaidecahedral voids. The larger voids are able to accommodate molecules including propane, isobutane, cyclopentane, benzene and others.
Structure H hydrates:were discovered recently and contain 34 water molecules for every 6 gas molecules giving a hydrate number of 5.67. The structure has three cavity sizes with the largest cavity able to accommodate larger molecules than both sI and sII. Once again, stability is only possible in the presence of smaller ‘help’ molecules such as methane and nitrogen.
FACTORS GOVERNING HYDRATE FORMATION: For stable hydrate crystals to form in oil and gas production systems, four essential elements must be present:
1- Supply of hydrate forming guest molecules like N2, CO2, H2S, CH4, C2H8, and other Hydrocarbon molecules
3- Low Temperature
4- High Pressure.
HYDRATE MITIGATION & REMEDIATION
Strategies for hydrate mitigation and remediation often modify one or more of these elements to destabilise the hydrate and thus remove the problem. However, hydrates can also be prevented by the injection of chemical inhibitors which seek to modify the chemistry of hydrate formation such that the system is operated outside the hydrate envelope or the kinetics of hydrate formation do not allow hydrates to form blockages during transit through the production system. The various methods of hydrate control can be summarized as follows:
1- Pressure Control: Design and operate the system with pressures low enough to maintain the fluids outside the hydrate envelope. This approach is often impractical for normal operation since the pressures required for transportation of production fluids would usually exceed the hydrate formation pressure at the ambient temperature. However, for the removal of hydrates following unplanned shutdowns, depressurisation outside the hydrate envelope is normal practice.
2- Temperature Control: Maintain the temperature of the production fluids by either passive insulation or active heating (e.g. direct electrical heating DEH) in order to prevent the system entering the hydrate envelope. The use of insulation to maintain the temperatures of production fluids outside the hydrate envelope at system operating pressures is an established approach to hydrate prevention during normal operation, particularly in black oil systems where hydrate prevention may often be a ‘byproduct’ of wax prevention. However, temperature control by passive insulation only offers hydrate control during normal operation when the system is being continually heated by hot production fluids. Following a shutdown the production fluids will cool down and can enter the hydrate envelope. Under these circumstances the traditional approach has been to depressure the system as discussed above, although recently active heating has been installed to prevent cooldown into the hydrate region by maintaining temperatures
3- Remove Supply of Water: Prevent the formation of hydrates by removing the supply of water using separation and dehydration. This approach has proved popular for the export of sales gas but is impractical for subsea applications.
4- Remove Supply of Hydrate Formers: Prevent the formation of hydrates by removing the supply of hydrate forming molecules perhaps by gas-liquid separation. This approach has been proposed for subsea operation where gas and liquids are separated subsea and are transported to the processing facilities in separate pipelines. The gas pipeline still requires hydrate inhibition (through chemical inhibitors) but the liquids line (containing oil and water) is able to operate satisfactorily without forming hydrates due to the absence of hydrate formers. It is not known whether such a system has yet been installed and operated in this way.
5- Inject Chemical Inhibitors: Inject chemical inhibitors into the system which modify the hydrate phase diagram or the kinetics/morphology of hydrate formation. Along with the use of insulation for temperature control (see above), the injection of chemical inhibitors has also found widespread application. The use of chemical inhibitors is a main focus of this paper and is discussed in more detail in the next section.
The injected Chemical Types are:
Thermodynamic Hydrate Inhibitors (THIs):These chemicals work by altering the chemical potential of the aqueous phase such that the equilibrium dissociation curve is displaced to lower temperatures and higher pressures. They are added at relatively high concentrations (10-60 wt% in the aqueous phase) and examples include methanol and monoethylene glycol (MEG). Inaddition, the naturally occurring inorganic salts which exist in both sea water and formation Water also act as thermodynamic inhibitors.
Kinetic Hydrate Inhibitors (KHIs):This class of chemicals does not alter the thermodynamics of hydrate formation but instead modifies the kinetics of hydrate formation. They achieve this both by prevention of nucleation and by hindering crystal growth. Their effect is time dependent and ultimately hydrates will form and block the pipeline but only if the transit time through the pipeline is sufficiently long, for example following a shutdown. KHIs are added at low concentrations (typically less than 1 wt% in the aqueous phase) and examples include poly[N-vinyl pyrrolidone] or poly[vinylmethylacetamide / vinylcaprolactam].
Anti-Agglomerants (AAs): These chemicals do not seek to prevent hydrate formation but rather to prevent the crystals from agglomerating and forming a blockage. They are surface active chemicals which adhere to hydrate crystals helping to stabilise the crystal in a continuous oil phase. Their main limitation is that they require a continuous oil phase and are therefore only applicable at lower watercuts. AAs are added in low doses (typically less than 1 wt% in the aqueous phase) and examples include alkyl aromatic sulphonates or alkylphenylethoxylates. AAs can also display a kinetic inhibition effect and are sometimes included in the class of KHIs.