Often wells are perforated and completions are run in a packer fluid that is designed to protect the well during production. This requires careful consideration and expert input at the design stage of the well. This section covers the important points behind comple- tion fluid decisions, but it is important to realize that this specialist area should have input from someone with expertise in completion fluids design.
Completion fluids must be as nondamaging to the formation as possible so they do not compromise productivity. Apart from being chemically and physically compatible with the reservoir and its con- tents, the solids content of the mud must be kept as low as possible. Any solids must also be removable by acid or other treatments. Damaging solid precipitates or emulsions can be formed downhole by chemical reaction between formation fluids and mud or brine filtrates, which also need to be prevented.
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Rheology and fluid loss properties may have to be controlled. Nondamaging additives or those that can be easily removed are need- ed for tailoring these properties. Calcium carbonate, graded by size depending on the formation pore sizes, makes an effective fluid loss agent that is acid soluble. Yield point (YP) and gels should be sufficient to avoid solids settling out unless a solids-free brine is used.
1.3.5. Brines
Brines can offer solids-free systems with densities up to 1.07 psi/ft (20.5 ppg). Another consideration is using solids-weighting materials that are acid soluble, such as calcium carbonate and iron carbonate .
While being able to overbalance formation pressures, properly designed brines do not create formation damage, neither by plugging the reservoir with unremovable solids nor by causing reactions with formation fluids or solids. Potential interactions of brines in the reser- voir include:
■ Scale from the reaction of a divalent brine with dissolved carbon
dioxide, producing an insoluble carbonate (divalent brines con- taining calcium or zinc salts, i.e., the metal ion has a valence of two)
■ Precipitation of sodium chloride from the formation water when it
is exposed to some brines
■ Precipitation of iron compounds in the formation resulting from
interaction with soluble iron in the completion fluid (most com- mon with zinc bromide, ZnBr2)
■ Reaction of formation clays with the brine
■ Corrosion of casings and tubulars (not such a problem with mono-
valent brines)
Consider corrosion and biodegradable properties for completion fluids that will remain in the well for a long time. Corrosion inhibitors are available to suit various muds and brines. The pH should also not be too high or too low to prevent damage to tubulars, cement, and elas- tomers. Biocides can help control bacterial activity.
Selection of a brine system. There are three main criteria to use in selecting the brine system for a particular well.
1. Density. Different brines have different ranges of possible densities. Downhole density can be significantly different to surface density due to the effects of pressure and temperature. This difference is greater with heavier brines. The desired density will restrict the choice of brine to use.
2. Compatibility. The brine system must be compatible with the reser- voir solids and fluids to ensure that solid additives, precipitates, or emulsions do not form and block the reservoir; and to minimize problems with the well (e.g., corrosion).
3. Cost. Different brine configurations are possible to meet the two criteria previously listed, but the cost can vary significantly depending on the salt(s) used.
Additives can be used in the base brine system to control other properties such as fluid loss.
Salts used in brines. The general salts used in the oilfield for brine formulation include sodium chloride, potassium chloride, calcium chloride, sodium bromide, calcium bromide, and zinc bromide. Other less commonly used salts include magnesium chloride, ammonium chloride, sodium formate, and potassium formate.
Some of these salts can be blended together to produce the most cost-effective recipe at a certain density. This is commonly the case when mixing high-density brines using expensive bromides.
Many salts, especially calcium chloride, are manufactured at a vari- ety of purities. When comparing costs of salts for formulating brines, base the calculations on the salt purity that will actually be supplied. The cost per unit of actual chemical is what should be compared.
Effects of temperature and pressure on brines. Often overlooked during brine planning is the effect of downhole temperature and pres- sure on the density of a column of brine. When calculating the required density this must be considered, especially when using high-density brines. This depends on several factors: brine type, brine density, well depth, ambient temperature, and bottom hole temperature.
Specialist companies can run a program for your specific well, plot- ting the temperature effect on the brine density against depth (See Fig. 1-4). This allows the average density at any depth in the hole to be cal- culated. This will determine the density that must be achieved at sur- face temperature to produce the desired density in the hole.
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Bottom hole temperature 365˚F
Surface temperature 60˚F
True vertical depth 18,100 ft Surface brine density 13.19 ppg
Using a calcium chloride/calcium bromide blended brine. Depth (ft) Temp (˚F) Pressure (psi) Density (ppg)
0 60 0 13.19 2,000 93 1,365 13.13 4,000 127 2,723 13.05 6,000 161 4,074 12.98 8,000 194 5,416 12.91 10,000 228 6,751 12.83 12,000 262 8,078 12.75 14,000 295 9,397 12.68 16,000 329 10,708 12.60 18,100 365 12,083 12.50
This report indicates that the average density in the hole is 12.85 ppg at TD.
Brine crystallization point and eutectic point. The crystallization
point of brine is the temperature at which salt crystals begin to fall out
of solution and thus reduce the density of the brine. The temperatures at which the brine will be transported and stored should exceed the crystallization point by at least 10˚F (6˚C). Crystallization can also plug lines and damage pumps.
There are three temperatures relative to crystallization occurrence:
first crystal to appear (FCTA), true crystallization temperature (TCT), and last crystal to dissolve (LCTD).
Adjusting the density of brine using dry salts affects the crystal- lization point. With single-salt solutions, adding more of the same salt initially lowers the crystallization point temperature to the eutectic
point. This is the lowest temperature of the crystallization point of a
solution. For example, the lowest crystallization point obtainable for
1.3.5 Well Design
Fig. 1-4 Example of Report—Temperature Effect on Brine Density Against Depth
calcium chloride brine is when the density reaches 10.8 ppg. Further addition of dry calcium chloride to a 10.8 ppg brine solution raises the crystallization point, even though the density continues to increase. For two-salt brines with a crystallization point of 30˚F (-1˚C), the addition of dry salt raises the crystallization point temperature. (See Fig. 1-5)
Fig. 1-5 Graph of Temperature vs. Crystallization Point
Brine additives. A solids-enhanced fluid is necessary for comple- tion or workover operations when the use of clear brine will result in the loss of large fluid volumes to the formation. Sized calcium carbon- ate is often used because it is completely acid soluble.
Treating the finished brine with corrosion inhibitor, oxygen scav- enger, and bactericide is recommended. Depending on the well condi- tions, other treatments such as a scale inhibitor or hydrogen sulfide scavenger may be required.
Since oxygen scavenger will be treated out by oxygen from the atmosphere, it should be added to the brine just before pumping on the final circulation. Ideally additions should be made using an injection pump directly into the suction line of the displacement pumps.