Prior to the1977 offshore operations on Dome/Canmar's vessels in the Beaufort Sea, it was determined that hydrate formation could be encountered during gas well tests. Although systems had been developed for methanol injection in arctic land operations, offshore operations required a system which would retain the advantages of a sub-sea test tree. A system was developed by Dome/Canmar, in association with Johnston Testers, which allowed the injection of methanol up to 2,000' below the sub-sea test tree, and which would allow the unlatching of the sub-sea test tree, while maintaining the full pressure integrity of the test string. The system also allowed closing of pipe rams during testing (to activate down hole pressure controlled test tools) and re-latching of the sub-sea test tree, if it was required to temporarily move off a well. The system was successfully used throughout Canmar's 1977 testing operations.
Hydrates will form and accumulate in a natural gas stream at predictable pressures and temperatures when the following conditions are met(1,2):
The pressure /temperature relationship of the gas must be below the dew point of the water vapour, and liquid water must be present.
The gas must be in motion and subjected to a degree of turbulence.
A foreign particle or a change in flow path must be present to interfere with the gas flow pattern.
All three of these conditions can be expected to occur during gas well testing in the Beaufort Sea. Hydrates may form in the upper portion of the tubing string where the gas loses its greatest amount of heat and may accumulate further upstream in the flow head and manifold system where the gas is controlled before it reaches the heater. In each of these locations, hydrates may plug the flow path resulting in a termination of the production test and a loss of effective rig time due to the need for depressuring and clearing the system.
On the other hand, hydrates can be prevented from forming by maintaining relatively high temperatures and low pressures throughout the flow stream or by fully inhibiting the water phase in the gas to lower the hydrate temperature. High temperatures can only be achieved after the well had been placed on stream for a time at high rates. However, during the initial flow period, inhibition is the only method that can reliably prevent the formation of hydrates.
Several operators were contacted for field evidence of hydrate formation on gas well testing in arctic and offshore areas.
On the North Slope, downhole hydrate prevention procedures vary. One method involves circulating hot calcium chloride solution down concentric strings until a suitable wellbore temperature is reached and the gas is maintained outside the hydrate formation pressure/temperature region. Gas well F.T.H.P' s in this case are in the range of 2,800 to 3,000 p.s.i.g. which requires a minimum gas temperature of approximately 75 °F to prevent hydrate formation, as shown in Figure 1.