BAKER HUGHES - Drilling Fluids Reference Manual

BOREHOLE PROBLEMS
Density
It is important to realize that drilling fluid density can vary significantly with temperature. This
variation is represented by a decrease in density with increasing temperature and is due to the
volumetric thermal expansion of the fluid phase. This is particularly true of oil based drilling
fluids as the oil continuous phase has a greater coefficient of expansion than does water.
Rheological Properties
In commonly utilized oilfield drilling fluids all rheological properties decrease with increasing
temperature. However under downhole conditions this effect may be reduced by increased
pressures and may be completely reversed (i.e. viscosity will increase) by the increased hydration
and flocculation of commercial clays and drilled solids. The presence in the wellbore of
contaminants such as calcium, magnesium and carbon dioxide can, under high temperature
conditions, cause the rheological properties of a water based drilling fluid to increase to such an
extent that it become un-pumpable. The viscosity of oil based and synthetic fluids also increases
with applied pressure.
Filtrate
Both API and HPHT filtrate increase with increasing temperature. This is largely due to loss of
product function, and to changes in filter cake compressibility with changing temperatures.
Above differential pressures of 100 psi pressure increases alone have little effect on clay based
drilling fluid filtrate indicating the effects of compressible filter cakes.
In general, polymers maintain their filtration control function well beyond the temperature at
which they lose any viscosifying capabilities. This is due to the fact that even short, broken
polymer chains are capable of functioning as filtrate control agents but not as viscosifiers.
Alkalinity
Temperature increases the rate and extent of most chemical reactions. The increased yield of
clays results in more sites being available for reaction with ions, particularly hydroxyl ions. The
end result of this is a reduction in alkalinity and an increase in flocculation. In oil based drilling
fluids increased reaction of lime with surfactants greatly increases with temperature and
reductions in drilling fluid alkalinity are common, particularly after lengthy trips. Often the
performance of the drilling fluid will be hindered by a lack of a sufficient excess of lime.
Methylene Blue Test (MDBT)
When using a water based drilling fluid the MBT is one of the most meaningful tests available to
indicate the general condition of the drilling fluid. The results of this test give an indication of the
amount and size of active clays in the drilling fluid. In normal wells a non-dispersed polymer
drilling fluid should, for example, have an MBT no greater than 20 lb/bbl. In high density drilling
fluids 15 lb/bbl. should be considered the upper limit. High temperatures can rapidly increase the
yield of commercial bentonite and reactive solids; this in turn will produce a rapid increase in
values obtained from MBT tests. Drilling fluids with high MBTs are susceptible to contaminants
that would not normally cause problems in low solids drilling fluids (e.g. calcium, carbonates,
etc.).
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 7-48