BAKER HUGHES - Drilling Fluids Reference Manual

Contamination of Water Based Fluids
drilling fluid properties to see the gradual onset of contamination and avoid deterioration of an
otherwise good system.
Rig site oven testing provides necessary data for monitoring and treatment purposes. Before
reviewing the types of chemical water fluid contaminants and their treatment, you may want to
reread Chapter 3, Water Base Drilling Fluids, which contains some fundamental principles and
basic definitions of water-base drilling fluid chemistry.
Calcium / Magnesium Contamination
The calcium and magnesium ions can be a major contaminant of water-base drilling fluids. Both
are divalent cations which attack clay and high molecular weight polymers by the same
mechanism. Calcium can enter the fluid as part of the make-up water or while drilling cement,
anhydrite, or gypsum. Also, connate water from penetrated formation and saltwater flows often
contain calcium ions and can become sources of calcium contamination. Magnesium can be
found in make-up water, formation water, and in formations such as the carnolite salt of the
Zechstein formations in the North Sea, and drilling operations in Saudi Arabia. In most sources of
cationic contamination the contaminant is a mixture of cations and normally one is more
dominate in concentration than the others. As in the case of the Zechstein formation it can vary
from almost pure sodium chloride to predominately magnesium and potassium salts.
Calcium contamination changes the nature of freshwater clay-based systems as shown by
rheology and/or filtration control problems. The calcium ion tends to replace the sodium ions
through Base-Exchange, which results in flocculation and aggregation of the clay particles. The
bound layer of water between the clay platelets is also reduced, resulting in diminished hydration
or swelling characteristics.
The effects of calcium or magnesium contamination on deflocculated fluids include,
• increased fluid loss values
• increased yield values
• increased gel strengths.
The severity of calcium or magnesium contamination (the degree to which this contaminant will
affect the fluid properties) will depend upon,
• the amount of the contaminating ion
• the amount, type, and distribution of solids
• the type and quantity of drilling fluid additives present in the system.
Calcium contamination originating from make-up water, formation water, or anhydrite is usually
treated with soda ash (.093 lb m /bbl per 100 mg/L Ca ++ ) or sodium bicarbonate (0.0735 lb m /bbl per
100 mg/L Ca ++ ). If the pH is below 10.0, the test specific to calcium should be employed (Betz
indicator, NaOH, and triethanolamine solution) to insure magnesium is not present.
Approximately 100 mg/L of Ca ++ should be left in the system to avoid over treatment. Excessive
soda ash treatment results in excess soluble carbonates, which could lead to rheological and
filtration control problems.
Magnesium, most often encountered when seawater is used as make-up water, has a similar
adverse effect on the fluid properties as does calcium. Magnesium can be precipitated with
caustic soda as insoluble Mg(OH 2 ). Theoretically, one-half pound of caustic soda per barrel of
fluid will precipitate approximately 430 mg/L of magnesium. Most of the magnesium ion will be
precipitated when the pH is increased to the 10.0 pH range. Other sources of magnesium are
Baker Hughes Drilling Fluids
Reference Manual
4-2 Revised 2006