0 4 8 12 16 20

Deplh of Drilling Damage, inches

Figure 10-20. Effect of mud damage while drilling on well productivity when perforated with a damaging fluid. (From Klotz, Krueger, and Pye.29 Copyright 1974 by SPE-AIME.)

of the formation has not been impaired while drilling (kf= 100%) permeability of the crushed zone (kp) is 20% of the original rock permeability, and productivity is 80% of potential. If the permeability of the formation has been impaired during drilling, productivity may be reduced to as low as 20% of potential, depending on the value of kf and the depth of invasion. Figure 10-20 shows that if the well is perforated with a damaging fluid in the hole, the permeability of the crushed zone may be reduced to as little as 5% of the original permeability, and the maximum productivity that can then be expected (even if there is no damage during drilling) is 45% of potential. These results show that perforating with a nondamaging fluid in the hole is of the utmost importance.

Workover Wells. Muds used in workover wells differ from drilling muds in that they usually have no opportunity to pick up bridging solids in the hole, so bridging solids must be included in the formulation. The importance of bridging solids was not realized in the past, and workover fluids containing only colloidal materials such as starch, CMC, guar gum, or bentonite, were often used. These fluids had the required rheological properties, and appeared to have acceptable filtration properties because the tests were made on filter paper. In the hole, however, they penetrated deeply into moderate and high permeability formations, causing considerable drops in productivity. Sometimes circulation was lost, in which case major losses of productivity occurred. Nowadays, common practice is to add bridging particles to workover fluids, but nevertheless, workover wells are especially liable to formation damage for several reasons. In the first place, the correct size of bridging particles is not known because previous production may have opened up flow channels of unknown size. Furthermore, changes in intergranular stress around the wellbore may have altered the pore structure, particularly if the well has produced sand.

Another problem is that reservoir pressures are usually low in workover wells, sometimes less than hydrostatic, and consequently mud overbalance pressures are apt to be high. A high pressure differential between the mud and the formation increases the mud spurt because of dynamic effects, and also increases the chances of loss of circulation through induced fracturing, Finally, workover wells are liable to impairment arising from damage to previous gun perforations, which are exposed to the workover fluid throughout the whole operation.29 Because of these various problems, it is generally advisable to use a degradable mud in workover operations.

Gravel Pack Operations. Plugging of the gravel by external filter cake left on the face of the formation poses a problem in gravel pack operations. In open-hole gravel packs, the cake will plug the gravel when the well is produced, unless it is readily dispersible in the produced fluids and the maximum particle size ol its. solids is less than one-third the size of the openings between gravel. Rather than rely on this mechanism, better practice is to use a mud with degradable solids when underreaming prior to gravel packing. It is obviously desirable that mud not be contaminated with drilled solids when underreaming; therefore, efficient mechanical separation must be provided at the surface, and muds that enhance the removal of the drilled solids while retaining the bridging solids must be used.

Completion of Water Injection Wells. Water injection wells are especially liable to impairment by mud solids because the flow is from the well into the formation when the well is completed. Thus, any solids left in the hole after washing the well will be carried into the formation by the injected water, or will filter out on the face of the borehole. Accordingly, degradable materials are advisable for use in completing or working over a water injection well.

Prevention of Formation Damage

The surest way to prevent formation damage by mud solids or filtrate is to operate with an underbalanced mud column, so that no solids or filtrate can invade the formation. Unfortunately, this operation is risky in high pressure wells. This method requires the use of special equipment and trained crews, and may not be economically feasible. In wells with hydrostatic formation pressures, an underbalanced column may be achieved by the use of oil-base fluids, but in drilling wells it is difficult to maintain the necessary low density because of the incorporation of drilled solids into the mud. However, in some types of workover operations, oil-base fluids or crude oil may enable an underbalanced column to be maintained. In very low pressure wells, gas or foam may be used (see the section on foaming, in Chapter 7).

In most wells, an overbalanced column must be maintained, and prevention of impairment requires the use of a non-damaging fluid. As already mentioned, damage to water-sensitive formations may be prevented by using inhibited muds, or brine fluids. Table 10 2 lists the minimum recommended concentrations for sodium, potassium, and calcium chloride brines. Nole that calcium and potassium chlorides have about the same inhibiting power, but calcium chloride suffers from the disadvantage that it may cause impairment by precipitating carbonates or sulfates, which are often present in formation waters.

Therefore, when the brine density required is less than 9.7 lb/gal and calcium ions are judged to be potentially damaging, potassium chloride is generally acceptable as a completion/workover fluid. If the density requirement is greater than 9.7 lb/gal and a calcium-free brine is desirable, then sodium bromide or potassium bromide may be used to obtain densities up to 12.5 lb/gal. In rare cases, zinc bromide brines have been used to provide high density calcium-free completion fluids. The idea here is that the acidic nature of the zinc ion will prevent precipitation with anions such as carbonate or sulfate. Compositions of various brines are presented in the following section on fluid selection.

The question of what constitutes a non-damaging fluid depends not only on the properties of the fluid but also on the completion or workover procedure in question. When the well is perforated and/or gravel packed, experience indicates that the wellbore should contain a solids-free or extremely clean fluid. 3u-bx Also, if possible, the perforations should be shot underbalanced. The problem with defining a non-damaging fluid is a trade off between high seepage loss to the formation, in the case of a solids-free brine, which may disrupt the equilibrium of the rock matrix or carry fine particles into the formation; and plugging of perforations and gravel packs in the case of a solids-laden fluid.

In general, perforations are shot in clear brines. In order to maintain the clarity of a solids-free brine, filters must be used during the circulation of the brine downhole. The most common approach to brine filtration is the use of a filter press utilizing diatomaceous earth as a filter aid and absolute micron rated filtration cartridges downstream from the press. This arrangement allows any type of brine to be filtered to turbidities of less than 5 NTU. If care is taken to properly clean the casing and tubing, the turbidity of the wellbore effluent can be as low as 5 to 10 NTU. (Note: NTUs do not correlate directly to solids content in ppm. but calibration curves may be prepared according to standard API practice. -M) Maly-'2 has emphasized the extreme care that must be taken to remove the contaminating solids at the surface, but even if this is done, enough solids may be picked up on the way down the tubing to cause considerable impairment Tuttle and Barkman33 showed that it was necessary to reduce the solids content of Louisiana bay water to less than 2 ppm in order to prevent significant impairment. Such reduction of solids content is possible with currently available filtration equipment as described above.

Given that wholesale loss of brine to the formation should be avoided when possible during completion and workover procedures, what can be done to stop fluid loss? The use of properly sized bridging solids may be the best approach. Remember, any solids in the well bore during perforating or gravel packing operations may cause considerable damage. Various types of soluble or degradable bridging materials are available commercially, and the choice between them depends on reservoir conditions and type of operation. Sized particles of oil-soluble resins or waxes may be used as bridging agents for oil reservoirs. Any particles left in or on the formation are dissolved when the well is brought into production. Obviously such particles are of no use in dry gas reservoirs or water injection wells. Organic particles have the advantage over mineral bridging agents in that their density is about one-half that of drilled solids. Thus, when drilling or underreaming the productive interval, the drilled solids may be removed at the surface by gravity separation methods without removing the bridging particles.

Ground carbonates (limestone, oyster shells, dolomite) were the first degradable bridging particles to be used in workover fluids, and are still frequently used. On completion of the job, they are removed with acid if necessary. Carbonates are inexpensive, and may be used in any type of reservoir, but suffer from the following disadvantages:

1. Acidization is an extra operation and an additional expense.

2. Acid may dissolve iron on the way down the hole, and iron compounds present in the formation. Then, when the acid is spent, the pH rises, and iron hydroxide is precipitated, causing considerable impairment.1 ' J s

3. All of the carbonate particles may not be contacted by the acid, which tends to follow the path of least resistance. To avoid this problem, alternate slugs of acid and diverting agent are necessary.

4. In reservoirs where the matrix cement is calcite, the acid tends to dissolve the calcite, releasing fines.

Regardless of these objections, carbonates are the most suitable degradable particles for use in dry gas reservoirs. Furthermore, the above objections do not apply to carbonate reservoirs that must acidized in any event.

Long chain polymers are used in degradable muds to obtain rheological properties, and, in some cases, filtration control. Unfortunately, most such polymers are, at best, only partially degradable. One sometimes reads in the literature, or in product specifications, of "water soluble" polymers, which suggests that the polymers are thereby non-damaging. In point of fact, none of these polymers enter into true solution; their particles are in the colloidal size range, and have chain lengths that may exceed 0.1 micron, which is comparable to the width of a medium sized clay platelet. If the particles penetrate deeply into the formation, they cause considerable impairment. Fhey are difficult to reverse out because they are adsorbed on silica surfaces and on the edges of clay lattices (see Chapter 4).

The damage that can be caused by polymers was shown by Tunic and Barkman,33 who injected polymer suspensions (containing no bridymg agents) into 450 md sandstone cores. With guar gum, they obtained only 25% of the original permeability after backflow, and 43% when the contaminating polymer was hydroxyethylcellulose (HEC) (see Figure 10-21a). Of course, in practice, bridging agents would be added to the suspension to prevent deep invasion of the polymer, but in the kinds of operations requiring degradable muds, effective bridging is not assured. To guard against the possibility of deep invasion, a degradable polymer should be used. HEC is almost completely soluble in acid, and Tuttle and Barkman obtained 90 100% return permeability after injecting acid into a core contaminated by it (see Figure 10-2lb). Guar gum will degrade over a period of time if an enzyme is incorporated in the formulation, but about 9% residue remains after degradation. This residue is sufficient to cause severe impairment. For example, Tuttle and Barkman obtained only 50% return permeability alter the gum had broken. However, derivatives of guar gum, such as hydroxyethyl and hydroxypropyl guar gum (see Figure 4 - 31) are degradable, leaving only 1 2% residue.34 Similarly, although starch itself is not acid soluble, starch derivatives, such a;> hydroxyalkylated and esterified starches are acid soluble.35

Selection of Completion and Workover Fluids Solids Free Brines

Various brines are used as completion or workover fluids. A summary of these brines is presented in Table 10-4.

The density of a brine is adjusted by altering the concentration of the salt or salts in solution. Because these salts are soluble in the water, calculation of brine composition is not straightforward. Hence, brines are prepared with the use of empirical blend charts. Examples of blend charts are given in Tables 10-5 through 10-8. Other blend charts are available from brine manufacturers and suppliers. Notice that all the brines are made from a few basic materials. These materials include stock brines, such as 14.2 lb/gal CaBr2, and dry salts such as CaCl2 or KC1. The manner in which these various materials are blended depends largely on the density and crystallization temperature requirements. Crystalliza-

Table 10-7 Calcium Chloride Brine
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