Gas hydrate formation during deep-water offshore drilling is a well-recognized operational hazard. Plugging the BOP stack, choke and kill lines with hydrates can cause a serious well control problem.
We conducted an up-to-date review of the drilling practices and mud formulations applied in deep water drilling as related to gas hydrates control and mitigation.
The review indicated that Salt/polymer mud systems are the most commonly used mud formulations in the Gulf of Mexico, North Sea and offshore Brazil. Drilling with these systems has been successfully achieved to water depths of up to 7500 ft (2287 m).
In the second part of this work, we measured the hydrate phase equilibrium of 25 drilling fluid formulations. The testing also included two new spotting fluids formulations. The testing results indicated that, on weight basis, NaCl is the best thermodynamic inhibitor among the salts tested in this work, which are NaBr, Na-Formate, KCl, and CaCl2. Although the high solubility of the Na-Formate makes it possible to increase the hydrate suppression beyond that of NaCl, the former is less effective on weight basis than NaCl.
The glycols are considerably less effective inhibitors, on weight basis, than the salts. However, greater degree of suppression can be achieved by using mixtures of salts and glycols. Among the tested glycols, ethylene glycol showed the best performance compared to AQUA-COLTMS, GEOMEGTM D207, and HF-100NTM.
Gas hydrate formation during deep-water offshore drilling and production is a well recognized operational hazard. In water depths greater than 1000 ft (300 m), the sea bed conditions of pressure and temperature become conducive to gas hydrate formation. In a well control situation, although the kick fluid leaves the formation at a high temperature, with an extended shut-in period it can cool to seabed temperature. With high enough hydrostatic pressure at the mudline, hydrates could form in the BOP stack, choke and kill lines, as have been observed in field operations
Record water depths are continuously being set by operators in search of promising reserves in deep waters. The first deep water well to be drilled in Norwegian deep water licenses will start in summer 1997. The extremely low mud line temperature of 28.4 to 30.2 F (−2.0 to −1.0 C) in this area brings the challenge of designing suitable drilling fluids that both prevent hydrate formation and meet other drilling requirements. The current practice in deepwater drilling is to suppress the hydrate formation temperature by using highly saline drilling fluids formulated from NaCl or other salts. This solution is applicable for the Gulf of Mexico, but insufficient for the conditions to be encountered in the Norwegian deep waters. At extreme water depths or extremely low mudline temperatures, this thermodynamic inhibition alone may not be sufficient to prevent hydrate formation. Instead, the use of kinetic inhibitors or crystal modifiers, in conjunction with thermodynamic inhibitors, may pave the way for successful operations in such an environment. The definition of kinetic inhibitors (to distinguish them from the classical thermodynamic inhibitors such as polar compounds and electrolytes) comes from the effect of the chemicals on the nucleation and growth of natural gas hydrates, both of which are time dependent and stochastic processes. The Impact of Drilling Fluid Ingredients and Additives on Hydrate Formation In a study of hydrate formation in drilling fluids, Guar et al. reported that salt and bentonite have the most significant impact on the hydrate phase equilibrium relative to any other mud component. This conclusion was based on a statistical analysis of 17 test runs performed at pressures below 1280 psia (8.83 MPa). The tested fluids contained variable amounts of bentonite, thinner, caustic, barite, salt, xanthan gum, partially hydrolyzed polyacrylamide (PHPA), oil, drill solids, and methanol.