BAKER HUGHES - Drilling Fluids Reference Manual

BOREHOLE PROBLEMS
The above figure shows pore pressure transmission results from various fluids. The 20% NaCl
+ PHPA + 3.5% v/v AQUA-COL D is a cloud point glycol fluid designed to cloud out in
the simulated drilling fluid/shale temperature gradient. A lower pore pressure build-up was
obtained with the polyglycol fluid than with the other water based fluids. The difference is too
great to be attributed to viscosity effects. It is believed that the following mechanism explains
this difference. A polyglycol solution is designed with a CPT that coincides with the BHCT,
i.e. at the bit the polymers are just starting to cloud out. This solution invades the shale under
the influence of hydraulic and diffusion gradients, and will experience temperature elevation
due to the higher Bottom Hole Static Temperature (BHST). Temperature induced phase
separation now occurs and emulsions are formed in situ, filling the shale pores. Possible, phase
separation forces the polymers onto the shale surfaces, coating them and changing their
wettability. The fraction of polymers deposited in situ now becomes a barrier that restricts
further fluid invasion and drilling fluid pressure penetration. Thus, the wellbore and shale pore
system are isolated and the shale is effectively stabilized.
Design Criteria for Polyglycol Drilling Fluids
1. The polyglycol molecules should be small enough to invade the shale pore network to
form an emulsion in situ. Typically, the molecular weight of the additives should be in
the range 500 – 2000 a.w.u. High molecular weight (>100,000) polyglycols are
restricted from entering shales due to their size, and will therefore not be effective in
closing off the shale pores.
2. The polyglycols should display cloud point behavior.
3. The CPT of the polyglycol solution should be tailored to coincide with the BHCT, in
order to fully exploit the temperature gradient between the wellbore and the formation
(BHST). The CPT may be changed in several ways:
• As polyglycols with different chemical composition will have different CPTs, the
right polyglycol may be chosen for the set of circumstances;
• The CPT can be influenced by changing salt content of the drilling fluid;
It is noted that matching the CPT to BHCT may be difficult when a long shale section
is drilled with continuously increasing BHCTs. There are two ways to tackle this
problem:
• The drilling fluid contains a blend of polyglycols with different cloud points, such
that glycols will cloud out at every BHST encountered;
• The salt content of the drilling fluid is depleted while drilling the section : lowering
the salinity will raise the CPT of the polyglycols.
Note: All of the above are most easily adjusted by use of GLY-CAD.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 7-20