BAKER HUGHES - Drilling Fluids Reference Manual

BOREHOLE PROBLEMS
contaminants such as the acid gases hydrogen sulfide and carbon dioxide are also present. Very
frequently high drilling fluid densities and considerable drilling depths are part of the overall
picture. Long trip times, which leave static, solids laden drilling fluid exposed to high levels of
contaminants, put many high temperature drilling fluids in exceptionally challenging
environments. Thermal degradation of drilling fluid additives (generating CO 2 ), can result in
unstable rheological and filtration properties.
High temperatures both disperse and flocculate bentonite suspensions. Hydration of
Montmorillonite (the major constituent of commercial bentonite) increases with temperature and
pressure and an increased number of clay platelets are split from aggregated stacks. A greater
number of particles are then present in the suspension and the viscosity of the suspension
increases. The split of aggregated stacks presents fresh surfaces for the adsorption of hydroxyl
ions producing a consequential drop in pH. This combination of increased surface area and drop
in pH will tend to increase flocculation within the suspension. Under downhole conditions this
creates a demand for alkali and deflocculant additions. If sufficient deflocculant is not present, or
the deflocculant itself is thermally degrading, severe flocculation or gelation can occur. This
condition is most commonly reached on a trip and problems re-establishing circulation can be
created. The actual temperature that triggers thermal flocculation depends on the fluid’s
composition. The type of bentonite, the type and concentration of drilled solids, the type and
concentration of deflocculant and the ionic composition of the liquid phase, all have an effect on
the flocculation process. The reaction of calcium ions with colloidal clays in a high alkalinity
environment can result in the formation of cement-like calcium-alumino-silicates. In these
situations extremely high gels can develop and, in the worst case, the drilling fluid may solidify.
Temperature effects on polymer drilling fluids are mainly due to the effects of temperature on the
constituent polymers. In most cases polymer drilling fluids are low solids fluids and all have a
degree of inhibition to clay hydration. The problem of increased clay hydration, seen in bentonite
drilling fluids, is rarely a problem in polymer systems. The polymers are, however, susceptible to
thermal degradation. Cleavage of the polymer chain can be accompanied by chemical
modification of the attached groups. The two primary reactions responsible for polymer
breakdown are oxidation and hydrolysis. Both of these processes can be controlled, to some
degree, by the maintenance of pH in the range 9.5 – 10.5 and by the use of oxygen scavengers.
The polar interactions between charged clays and polymers that take place in water based drilling
fluids do not occur in the non polar phase of a non-aqueous-based drilling fluid. Only relatively
weak hydrogen bonding can occur. These weak forces are readily broken by increases in
temperature so thermal degradation of non-aqueous-based drilling fluids is not common.
Temperature Limits
The following tables give approximate decomposition temperatures, or practical thermal
application limits, for water based drilling fluids products and systems. Correctly formulated nonaqueous-based
drilling fluids can perform effectively on wells with bottom hole temperatures as
high as 500°F (275°C).
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 7-46