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Safety and the Environment
The Planning Process
Fluid Categories
Fluid Density
Crystallization Temperature
Temperature and Pressure Effects
Estimating Required Fluid Volume
Fluid Compatibility
Fluid Compatibility

Reservoir mineralogy, especially the percentage and type of clays that will be encountered, may influence your decision as to the type of CBF best suited to a particular formation. The dominant cation (positively charged ion) in the brine, for example, ammonium (NH4+), sodium (Na+), potassium (K+), calcium (Ca+2), or zinc (Zn+2), will react with clay minerals to promote stability or act as a dispersant. Compatibility testing of core samples from the reservoir is the most reliable means of assessing the response of clay minerals to a brine. Experience in offset wells should also be considered if existing data indicates sensitivity of clay minerals.

Contact a TETRA fluids specialist to arrange for brine compatibility testing.

Reservoir Fluid Chemistry

Reservoir fluids are in a state of chemical equilibrium with the reservoir minerals. This state of equilibrium will be disturbed once a formation is penetrated and production activities begin. Prior to producing the well, the potential for formation damage resulting from reactions between formation fluids and drilling or completion fluids will exist. The chemical composition of formation waters should be evaluated for compatibility, paying attention to the degree of saturation with salt (NaCl) and any bicarbonate and sulfate ion concentrations.

Metallurgy and Elastomers

Clear brine fluids must also be compatible with the materials used in downhole equipment and with any tools with which they will come into contact. Temperature, pressure, and mechanical stresses can result in corrosion induced by the interaction between clear brine fluids and various types of metals. The increase in HPHT drilling has led to greater use of corrosion resistant alloys (CRAs) in production tubing. The incidence of catastrophic tubing failure due to environmentally assisted cracking (EAC) has risen with the increased use of CRAs. Because of these failures, compatibility of completion and packer fluids with CRA tubing has become a critical consideration, especially when planning HPHT wells. To provide empirical data to support its customers, TETRA has participated in extensive research aimed at understanding the causes of EAC and the steps that can be taken to decrease the probability of its occurrence. TETRA fluids specialists can provide technical guidance in the proper design of a clear brine fluid system.

Chemically and mechanically induced interactions should be assessed by TETRA’s fluids experts. If you are planning an HPHT well, ask for a customer recommendation report from the CRF selector.

MatchWell Engineered Fluid Systems

There are occasions when you may suspect compatibility issues or return permeability problems. These exceptional conditions may require a MatchWell engineered fluid system approach involving TETRA’s specialty brine blending, a Crack Reducing Fluid (CRF™) selector recommended fluid, or a nonconventional fluid.

When your data suggests that out of the ordinary conditions may exist in a well or producing zone, it is best to obtain the advice of your TETRA fluids specialist and TETRA technical service professional who can help you explore alternatives. Because these are unique situations, each one should be investigated and recommendations should be developed on the basis of available test data.

Some of the conditions that may arise and require unique approaches to completion fluids may include:

  1. density range, bottomhole temperature, and pressure conditions,
  2. dispersible or water sensitive clay minerals,
  3. metallurgical considerations such as high chromium alloys, and
  4. compatibility problems between formation fluids and the completion fluid.

Reasons to Consider a Specialty Fluid

When making a fluid selection, there are many things you need to consider. Table 6 gives a relative weighing of some of the considerations that will enter into a decision to use one type of specialty fluid over another. The decision will usually be based on one primary criterion and others will be weighed to a lesser degree. If a fluid has a distinct advantage in a particular category over other fluids in the same density range, a plus sign (+) is shown in that column. An equal sign (=) indicates no distinct advantage over fluids in the density range. Finally, a minus sign (–) indicates that a fluid has a disadvantage over other fluids in that particular density range.

Blue Line
TABLE 6. Specialty Brine Considerations

Brine Shale/Clay Acid
Carbonate Sulfate
Ammonium Chloride (NH4Cl) + + +
Potassium Chloride (KCl) + = + +
Sodium Chloride (NaCl) = + +
Sodium Bromide (NaBr) = + +
Sodium Formate (NaO2CH) = + + +
Potassium Formate (KO2CH) + + + +
Calcium Chloride (CaCl2) + =
Calcium Bromide (CaBr2) + =
Cesium Formate (CsO2CH) = + + +
Zinc Bromide (ZnBr2) + = +
+ advantage
= parity to other options
– disadvantage

Shale/Clay Dispersion

Many clay minerals will swell and can potentially disperse when exposed to the sodium ion (Na+). In general, fluids containing potassium (K+) and ammonium (NH4+) ions have a tendency to stabilize clay minerals by adsorbing into the clay structure. Divalent ions such as calcium (Ca+2) and zinc (Zn+2) also strongly adsorb into many clay minerals and create a nondamaging environment in the vicinity of the wellbore.

Acid Corrosion

Corrosion of metallic surfaces that come into contact with brines is strongly accelerated by the presence of the hydrogen ion (H+). The hydrogen ion can be essentially eliminated by raising the pH of a brine. The pH of fluids containing sodium, potassium, or calcium can be raised into a range where only negligible concentrations of hydrogen ions are present. Adjusting the pH of fluids containing ammonium or zinc ions is not recommended, as those ions are not stable at the pH levels that can be attained in other CBFs.


Formation waters are in a state of chemical equilibrium with formation minerals. Certain calcareous reservoirs with a high partial pressure of carbon dioxide may be incompatible with fluids that contain the calcium ion. Mixing formation water and calcium containing CBFs may result in the precipitation of calcium carbonate at the point of contact between the two fluids. The formation of calcium carbonate can result in permeability reduction, which is difficult to reverse even with strong acid stimulation. If formation water analysis indicates high levels of the bicarbonate ion (HCO3+1), fluids containing calcium should be avoided.


If formation water contains the sulfate ion (SO4-2) at a concentration of more than 500 ppm, it will react with the calcium ion to form a precipitate that will not readily respond to acid stimulation. Analysis of formation water will provide the only reliable means to assess the potential for this type of formation damage.

Of additional concern, the sulfate ion may also be converted to H2S by sulfate reducing bacteria. If this conversion occurs, the associated health and corrosion issues will have to be addressed.

The Next Steps

The information outlined in the preceding sections has explained the first stages of completion fluid planning. At this point, the general brine family, density (corrected for temperature and pressure), crystallization point, metallurgy, and volume of fluid required for the job have been determined. The following chapter goes through the processes and systems associated with a CBF job. Information is arranged by system.

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