Here's the info re Anti-Freeze ...I just had to know so I poked
around...This is a very informative page...I didn't
put what I posted as snippets because I wasn't sure
as each section on the page has it's own title...
so I apologize if I did it wrong...
Hydrates in natural gas processing
Methane clathrates (hydrates) are also commonly formed during natural gas production operations, when liquid water is condensed in the presence of
methane at high pressure. It is known that larger hydrocarbon molecules such as ethane and propane can also form hydrates, although as the molecule
length increases (butanes, pentanes), they cannot fit into the water cage structure and tend to destabilise the formation of hydrates.
Once formed, hydrates can block pipeline and processing equipment. They are generally then removed by reducing the pressure, heating them, or
dissolving them by chemical means (methanol is commonly used). Care must be taken to ensure that the removal of the hydrates is carefully controlled,
because of the potential for the hydrate to undergo a phase transition from the solid hydrate to release water and gaseous methane at a high rate as
the pressure is reduced. The rapid release of methane gas in a closed system can result in a rapid increases in pressure.
It is generally preferable to prevent hydrates from forming or blocking equipment. This is commonly achieved by removing water, or by the addition of
ethylene glycol (MEG) or methanol, which act to depress the temperature at which hydrates will form (i.e. common antifreeze). In recent years,
development of other forms of hydrate inhibitors have been developed, such as Kinetic Hydrate Inhibitors (which dramatically slow the rate of hydrate
formation) and anti-agglomerates, which do not prevent hydrates forming, but do prevent them sticking together to block equipment.
Effect of hydrate phase transition during deep water drilling
When drilling in oil- and gas-bearing formations submerged in deep water, the reservoir gas may flow into the well bore and form gas hydrates owing to
the low temperatures and high pressures found during deep water drilling. The gas hydrates may then flow upward with drilling mud or other discharged
fluids. As they rise, the pressure in the annulus decreases and the hydrates dissociate into gas and water. The rapid gas expansion ejects fluid from
the well, reducing the pressure further, which leads to more hydrate dissociation and further fluid ejection. The resulting violent expulsion of fluid
from the annulus is one potential cause or contributor to what is referred to as a "kick". (Kicks, which can cause blowouts, typically do not
involve hydrates: see Blowout: formation kick).
Measures which reduce the risk of hydrate formation include:
* High flow-rates, which limit the time for hydrate formation in a volume of fluid, thereby reducing the kick potential.
* Careful measuring of line flow to detect incipient hydrate plugging.
* Additional care in measuring when gas production rates are low and the possibility of hydrate formation is higher than at relatively high gas
* Monitoring of well casing after it is "shut in" (isolated) may indicate hydrate formation. Following "shut in", the pressure rises as gas
diffuses through the reservoir to the bore hole; the rate of pressure rise will exhibit a reduced rate of increase when hydrates are forming.
* Additions of energy (e.g., the energy released by setting cement used in well completion) can raise the temperature and convert hydrates to gas,
producing a "kick".