BAKER HUGHES - Drilling Fluids Reference Manual

BOREHOLE PROBLEMS
Polyglycol Shale Stabilization Mechanism
Below the CPT, the soluble polyglycols viscosify the drilling fluid filtrate. This filtrate will
invade the shale, but the rate of invasion is retarded by the viscosity enhancement. When the
temperature is above the CPT, the polyglycol solution becomes thermodynamically unstable,
triggering phase separation of the polyglycols to form a concentrated emulsion. In this macromolecular
state, the polymers can no longer enter the shale and are also very ineffective at
closing off the shale pore throats. Therefore, they do not have an effect on reducing fluid
invasion of shales. Note, however, that not all of polyglycol will cloud out at the CPT. In fact,
just above the CPT the majority of the polyglycol product remains in solution and determines
the viscosity of the continuous phase. The dissolved fraction of polymers will enter the shale
pore system unrestricted, and again the rate of pressure transmission is retarded by a factor
equal to the filtrate viscosity enhancement. The soluble polyglycol fraction will only cloud-out
if temperature is raised far beyond the CPT. As an example, for a certain 5% polyglycol
solution with a CPT of 60°C, 100% phase separation will not occur unless temperature is raised
above 90°C.
The discussions above emphasize the role of viscosity, and may be an explanation why good
results have been obtained in the field with clouding polyglycols used far below or above the
cloud point, and polyglycols that have no CPT. It should be noted, however, that relatively
high concentrations (>10% v/v) of polyglycols are necessary to obtain the desired viscosity
effects.
Under realistic downhole circulating conditions, a drilling fluid at bottom-hole circulating
temperature (BHCT) contacts a shale at a higher bottom-hole static temperature (BHST), i.e. a
drilling fluid/shale temperature gradient exists. Thus when a drilling fluid invades a shale, it
heats up, thereby changing temperature dependent fluid properties.
300
2 - 3% Sea Salt
20% NaCl Solution
200
20% NaCl + PHPA
Pressure (psi)
150
100
20% NaCl + PHPA + 3.5% v/v Aquacol D
50
0
80/20 Synthetic / 20% CaCl2
0 5 10 15 20 25 30 35 40
Hours
Figure 7 - 7 Typical PPT Data For Various Fluids
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 7-19