|Publisher||Society of Petroleum Engineers||Language||English|
|Content Type||Journal Paper|
|Title||Inhibition of Gas Hydrates in Water-Based Drilling Muds|
|Authors||Kotkoskie, T.S., Dow Chemical Co.; Al-Ubaidi, B., Wildeman, T.R., Sloan, E.D., Colorado School of Mines|
|Journal||SPE Drilling Engineering|
|Volume||Volume 7, Number 2||Pages||130-136|
In an effort to better understand the equilibrium conditions for hydrate formation in water-based drilling fluids, a series of thermodynamic experiments were run on sixteen simulated drilling muds and associated test fluids. Results indicated that to a first approximation the salt and glycerol content of water in mud dominated hydrate formation. To a lesser degree other mud additives such as bentonite, barite, polymers, etc. collectively promoted hydrate formation slightly.
As a result of increased deepwater drilling, the potential for natural gas hydrate problems while drilling has increased in recent years. Since hydrate formation favors high pressures and low temperatures, the deep ocean floor provides the proper conditions for hydrate formation in water-based drilling muds. Hydrates have recently been reviewed, and indeed documented in a number of deep ocean sites. In water-based drilling muds, hydrates may cause problems in two ways. First, the hydrates may form a "plug" or solid mass within the wellbore. This plug could begin in an area of little or no circulation, such as choke lines, kill lines, recesses within the blow out preventers (BOP), etc. Once formation has been initiated, growth may be quite rapid and could then spread to other parts of the system. Due to their mechanical strength, a large mass of hydrates may be able to prevent a drill string from rotating.
The second way which hydrates may cause problems results from their physical makeup. The water needed during formation comes the water-based drilling mud itself. The loss of water from the mud causes flow properties to deteriorate severely. In the most extreme scenario, all solids will settle out, leaving little or no fluid in the wellbore.
This combination of problems would make well control extremely difficult. As a result of the potential for such extreme problems, work has been underway in recent years to help understand, and ultimately prevent, hydrate formation in drilling fluids.
Barker and Gomez provided two dramatic examples of the problems which hydrate formation can cause. In their first case study, they reported the formation of hydrates during drilling operations off the California coast. This occurred in 1150 ft of water. The hydrates plugged the choke and kill lines, necessitating cementing operations to secure the well. The second case study involved hydrate formation in a well located in the Gulf of Mexico in 3100 ft of water. Choke and kill lines and other subsea equipment became plugged. Well control was finally achieved after numerous attempts.
Recently, Hale and Dewan showed the effects of salts and glycerol on hydrate formation in deepwater applications. At the same time, Lai and Dzialowski reported laboratory hydrate formation results in simulated drilling fluids. Their results indicated that for many of the fluids studied, hydrates could be formed at relatively low ( less than 2000 psig) pressures. In addition, they provided a correlation for inhibition based on salt concentration.
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