BAKER HUGHES - Drilling Fluids Reference Manual

Baker Hughes Drilling Fluids
saltwater flows and field brines. Generally, dilution, additional filtrate control agents,
deflocculants and caustic soda are required to restore the drilling fluid properties after magnesium
contamination.
Cement Contamination
In most drilling operations cement contamination occurs when the casing is cemented and cement
plugs are drilled out. If the plug is drilled while it is still green, the severity of calcium
contamination can be very high, as is the case when displacing should the cement return not be
diverted before it communicates with the active system. The extent of contamination and its
effect on fluid properties depends on solids content and type, concentration of deflocculants,
concentration of pretreatment chemical, and the quantity of cement incorporated.
Cement contains compounds of tri-calcium silicate, calcium silicate, and tri-calcium aluminate,
all of which react with water to form large amounts of calcium hydroxide Ca(OH) 2 . It is the
calcium hydroxide (lime hydrate) in solution that causes most of the difficulty associated with
cement contamination.
Lime in drilling fluids causes chemical reactions which can be detrimental to rheological and
fluid loss properties. The presence of OH¯ ions increases the pH and the calcium ion affects clay
characteristics. Significant pH increases could lead to a pH shock. Some polymers such as
Xanthan gum or PHPA are sensitive to higher pH levels and their chemical state is altered if pH is
too high. If cement contamination reaches a level where it is no longer practical to be treated out,
the most contaminated fluid should be discarded. In extreme cases it may be necessary to
displace the entire system or convert it to a calcium based fluid (lime mud).
Freshwater, bentonitic systems will be flocculated by cement, resulting in increased rheology and
fluid loss. The severity of flocculation depends upon the factors mentioned above. If cement
contamination reaches a level where it is no longer practical to treat it out, dump the most
contaminated fluid, displace the entire system out, or treat the system as a calcium-based fluid.
To maintain a low-calcium drilling fluid, chemical treatment must be used to remove cement
contamination. The aim of treatment is to control pH while removing calcium and excess lime
from the system as an inert, insoluble calcium precipitate.
Be aware that 100 lb of cement can potentially yield 79 lb of lime which is then available to react
with the drilling fluid. The volume of one sack of cement (94 lb) in most cases is 1.1 cu ft when
set. So, if you know the volume of cement drilled, you can make better predictions of the type of
treatment. This can be done by assuming the maximum quantity of cement which could be put
into the system from drilling the cement. For instance, if the diameter to be drilled is 8.5 in., each
foot of hole contains 0.394 cu ft of cement, or 33.7 lb of cement, or 26.5 lb of lime. This is the
maximum amount of lime that can be put into the system, assuming that all the cement drilled is
incorporated. When cement is completely set, assume 10% is normally available for
contamination. When cement is still soft (commonly referred to as “green” cement), as much as
50% of the cement could be dispersed and available to react with the fluid.
To chemically remove 100 mg/L of calcium originating from cement would require
approximately 0.0735 lb m /bbl of bicarbonate of soda or 0.097 lb m / bbl of SAPP. Lignite
(LIGCO ® ) will also react with lime to form a calcium salt of humic acid. Approximately 1 lb m /bbl
of lime can be precipitated with 7 to 8 lb of lignite. Treatments in excess of this range are not
recommended since calcium salts of humic acids may also create viscosity problems at higher
concentrations.
Excess lime can be estimated from the filtrate alkalinity ( P f ), fluid alkalinity (P m ), and volume
fraction of water by retort analysis (F w ) by the following equation.
Baker Hughes Drilling Fluids
Reference Manual
Revised 2006 4-3