BAKER HUGHES - Drilling Fluids Reference Manual

BOREHOLE PROBLEMS
• An unplanned increase in drilling fluid rheological properties could be due to a build up
of fine solids in the drilling fluid which in turn could be an indication of poor inhibition
or hole washout.
• The downhole loss of whole drilling fluid would indicate that the formation was being
fractured by the use of too high a drilling fluid density.
• Difficulty running in the hole could be attributed to ledges, swelling clays or caving
formations.
The caliper log can be run at section TD. The gauge of the hole will give an indication of
whether drilling fluid density and inhibition was at a correct level for that interval. If an
oriented 4-arm caliper is used, information on stress orientations can be obtained. A typical
indication of stress induced borehole instability is the presence of an oval rather than a circular
hole. Information regarding the two horizontal in situ stresses can be deduced from this type of
log. Knowing the direction of the stresses is valuable when planning development wells as the
well directions least prone to hole problems can be established.
Special Cases
Salt Formations
• Drilling near a salt diapir (salt intrusion as in salt dome) presents a special case because
of the altered in situ stresses near to the diapir. The behavior of wells within a few
hundred meters of a diapir may be totally different to wells only a kilometer or so away.
In general hole problems are accentuated near a diapir.
• The maintenance of gauge or near gauge hole is important when drilling massive salt
formations. Greatly washed out hole will probably result in a poor cement job. This in
turn will allow salt behind the casing to creep, impinging on the casing and, in extreme
cases cause the casing to buckle.
• Stuck pipe is a common problem when drilling salt formations. Salt formations tend to
creep and impinge on the drillstring. The only way to stop this process is to drill with a
drilling fluid density equivalent to overburden gradient (approximately 19 ppg in the
Southern North Sea and 17 ppg in the Gulf of Mexico). In practice the rate of creep can
often be reduced to acceptable levels at lower drilling fluid densities, typically 14.0 ppg.
The use of eccentric bits to slightly increase the diameter of the hole has proved
beneficial in some operations. Figure 7 – 3 describes the approximate mud weight to
control salt creep as a function of hole temperature and hole depth.
• Drilling massive salt sections with OBM/SBM generally produces an in-gauge hole. In
many cases, the creep of the salt results in the drill bit becoming stuck. Pumping a slug
(5 – 10 bbl) of fresh water down the drill pipe past the bit generally frees the bit. The
small volume of water should not affect the stability of the OBM, but the system should
be treated with additional salt to bring the water phase salt concentration back to required
levels.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 7-9