Tct In Drilling

+ 55 TCT

* Based on 95% CaCl2

1 TCT (thermodynamic crystallization temperature)

* Based on 95% CaCl2

1 TCT (thermodynamic crystallization temperature)

Table 10-8 Sodium Chloride/Sodium Bromide Brine

Density H20 NaCl* NaBr* Freezing Point

* Based on 100% NaCl and 95% NaBr + TCT (thermodynamic crystallization temperature)

tion temperature is matched to environmental conditions. Density and crystallization temperature are determined according to standard API procedures.31"1

Because of the potential for formation damage caused by loss of fluid to the formation,36 brines used in completing or working over highly permeable zones may require added bridging solids to control loss of fluid. Brines may also be difficult to use when the producing horizon contains unconsolidated sands, because they do not prevent slumping and washouts.363 As discussed in Chapter 8, slumping can only be prevented by the deposition of a filter cake on the walls of the hole so that the pressure overbalance is applied on the face of the formation. Clear brines may require increased viscosity or the use of viscous pills when cuttings, millings, etc. must be cleaned out of the hole, because they have low viscosities and no yield point. Hence, their carrying capacity is low.

Viscous Brines

Viscous brines have been used in order to avoid the various disadvantages of acidizing filter cakes as discussed above. In order to limit invasion into the formation, the brines are thickened to high viscosities (up to several hundred cp) with hydroxyethyl cellulose (HEC). These viscous brines contain no bridging particles. Hence, no external filter cake is formed and no positive shut-off obtained. However, the rate of invasion is reduced because of the high viscosity. According to Scheuermann in some cases a minimum of 4.2 lb/gal (12 kg/m3) HEC may be required to obtain the necessary viscosity (see Figure 10-22).

In practice, a pill of the viscous brine is spotted across or above the perforations of the loss zone. The volume of the pill should be sufficient to penetrate into the zone at least three feet. A viscosity breaker should be added to the pill to





70 80 90 100 110 120

lb/1000 gal


70 80 90 100 110 120

lb/1000 gal


Figure 10-22. Effect of polymer concentration on apparent viscosity. (From Scheuermann Copyright 1983 by SPE-AIME.)

enable it to baekflow out of the formation at the end of the job. However, most commonly used HEC breakers act in a matter of a few hours up to a day or so. Thus, they are useful only for short-term jobs. For longer jobs, reliance has traditionally been placed on thermal degradation of the HEC. However, based on the data from Figure 10-23, breakdown of the HEC within practical time limits in most formations is unlikely. The exceptions would be applications at very high temperatures (>275°F) or in low density brines (<11.6 lb/gal). Remember that even low viscosity HEC fluids can cause permeability impairment if the polymer remains stable (see Figures 10-21 a and b.)

An approach to the use of viscous pills, which have been used successfully for seepage loss control, is the use of low density brine as the medium for the pill The low density viscous brine is actually squeezed into the formation instead of spotted in the well bore. This allows it to be used in the presence of higher density brines without pressure control problems. Also, a crosslinkable HEC polymer has been used to control seepage loss in extremely permeable zones.

80 lb HEC/IOOOgol

-dry HEC

ilurry HEC IN O 11 pp9 CoClj A 15 7ppg (WINTER GRADE) 50% BROKEN IN 27 DAYS

Figure 10-23. Viscosity breakback times. {From Scheuermann Copyright 1983 by SPE-AIME.)

HEC is very slow to develop viscosity in brines of density greater than 12 lb/ gal (1.4 SG). Even when heated, up to five hours mixing time may be required in order to reach maximum viscosity. A probable reason for this behavior is that the hydration of the calcium and zinc ions alters the solvation energy of the water so that the HEC does not yield unless heated. HEC is used in these heavy brines in the field by first prehydrating the polymer in an inert solvent, such as isopro-pyl alcohol, then mixing it into the brine. This process does essentially the same thing as heat. In certain brines containing zinc, HEC will not yield even when heated or prehydrated. For these situations the zinc concentration must be increased to a sufficiently high level, relative to the other salts, so that the solution will solvate the prehydrated HEC. (Note: The minimum zinc concentration is approximately 7.5-9.0% by weight.)

Water-Base Fluids, Containing Oil-Soluble Organic Particles

Several types of fluids use oil-soluble organic particles, such as waxes and resins, to act as bridging agents. In some of these fluids, the particles are deformable at low enough temperatures to act as filtration control agents as well as bridging agents. These systems operate best at temperatures between 150° and 200°F (65-95°C). The particles become too rigid at temperatures below I50°F, and too soft at temperatures above 200°F. In the system described by Fischer et al37'38 the organic particles consist of a blend ol wax, surfactants, and an ethylene-vinyl co-polymer. Filter losses down to 24 cm \ API, can be obtained with these particles, and down to 7 cm3 by the addition of a chrome lignite. HEC and xanthan gum are used for rheological control, if required. Densities up to 10 lb/gal (1.20 SG) can be achieved with potassium chloride.

The thermoplastic resin particles in the system described by Crowe and Cryar"' are sufficiently deformable to provide filter losses down to 7 cm3 without the addition of a supplementary agent, but control is lost on rocks of permeability greater than about 900 md. This system has the advantage of being stable in all brines up to saturation.

Suman40 describes a system in which the thermoplastic resins—which have a much higher softening point [360°F (182°C)]—provide bridging requirements only, and do not contribute to filtration control. Starch derivatives, or other polymers, provide filtration control, and HEC is used to obtain carrying capacity when necessary. This system is also stable in all brines up to saturation at temperatures up to at least 300°F (149°C).

Acid-Soluble and Biodegradable Systems

Ground calcium carbonate is commonly used as a bridging agent in acid soluble and biodegradable systems. It is completely soluble in acid, and is available in a wide range of particle sizes, from several millimeters down to hundredths of a micron, and may be used at any temperature encountered in an oil well. Tuttle and Barkman33 found that, if suitable size ranges were selected, suspensions of calcium carbonate alone could be used for short term remedial work in gun perforated wells. However, for most purposes, it is necessary to add polymers for filtration control and carrying capacity. Polymers that are commonly used include CMC and polyacrylonitrile, which are not acid soluble; xan-than gum (50% acid soluble) and guar gum, which may be degraded with enzymes as previously noted; and starch derivatives and HEC, which are almost completely acid soluble. Note that magnesium oxide must be added to HEC to provide high temperature stability.41 Calcium lignosulfonates are used as supplementary filtration control agents, when needed. Both guar gum and HEC have low YP/PV ratios and are nonthixotropic, which is advantageous because of increased efficiency in separating gas and extraneous solids. For applications that require high carrying capacity and suspending properties, XC-polymer (Xan-than gum) is a better choice.

Saturated NaCl or KC1 brine may be weighted up to 15.0 lb/gal (1.80 SG) using finely ground CaC03. The particle size range of the CaC03 should be from 1 to 40 microns with an average of 6-10 microns to optimize suspension of the solids and filtration control. Also, FeC03 can be used to obtain densities be yond 15.0 lb/gal (1.80 SG). However, during acid clean-up, remember the possibility of ferrous hydroxide precipitation if the pH exceeds 7. FeC03 should be used in a calcium-free brine, i.e., NaCl or KC1, because in the presence of calcium ions, the FeC03 converts to a hydroxide-oxide of iron similar to the mineral Goethite or Limonite. Also, the particle size must be very fine to prevent errosion of metal goods such as pump liners and valves.

Fluids With Water-Soluble Solids

A completion and workover fluid has recently been introduced which uses sized grains of sodium chloride as bridging and weighting agents.42 The grains are suspended in saturated brine by a polymer and a dispersant (both unspecified). Densities up to 14 lb/gal (1.68 SG) are attainable. When the well is brought into production, the salt grains are removed by formation water, or the well may be cleaned by flushing with undersaturated brines. This fluid would obviously be especially suitable for water injection wells.

An Oil-in-Water Emulsion for Gun Perforating

Earlier, the importance of using a non-damaging fluid when gun perforating was emphasized. Priest and Morgan,41 and Priest and Allen.44 developed a solids-free emulsion specifically for this purpose. Typically, it consists of 40";. oil emulsified in sodium chloride or calcium chloride brine.

The oil phase is either kerosene or carbon tetrachloride, or mixtures of same, depending on the density required. Maximum density is 12.5 lb /gal (1.50 SG). The emulsion is stable enough to provide filtration control for 24 hours.

To minimize costs, only a slug of emulsion is pumped into the well, and spotted opposite the interval to be perforated, the density having previously been adjusted so that it maintains this location. Results from the field showed that the emulsion caused no impairment either when perforating or during workover jobs with exposed perforations.

Oil-Base Fluids

Under most conditions, conventional oil-base muds make excellent fluids for drilling through the productive interval. Indeed, they were first developed for this purpose. Their low mud spurt minimizes particle invasion, and their filtrate, being oil, does not cause waterblock or impair water-sensitive formations. Laboratory and field tests have shown that oil muds cause less impairment in water-sensitive formations than do conventional water-base muds.1-'44,45'46'47,48 Limitations on oil muds are that they may cause changes in wettability, and that they are unsuitable for use in dry gas reservoirs.

However, conventional oil-base muds are not readily degradable, and therefore should not be used under the conditions, already discussed, which make the use of a degradable mud advisable. Oil muds are designed for maximum stability while drilling; any water that they contain, or pick up while drilling, is tightly emulsified by powerful surfactants. Thus, there is a danger of emulsion blocking should bridging fail and the whole mud penetrate deeply into the formation. One would expect the low viscosity oil muds (see the section on drilling rate in Chapter 9) to be less likely to cause emulsion blocking, since they contain less surfactants and have higher oil/water ratios.

In reservoirs with aromatic crude, damage from asphalt in asphaltic oil muds will automatically be removed when the well comes on production, because asphalt is soluble in aromatic oil.49 Otherwise, it may be removed by washing with aromatic solvents. Asphalt muds should not, however, be used in condensate reservoirs, because asphalt is precipitated by light hydrocarbons, such as hex-ane.

Some success in reversing damage caused by all types of oil muds has been reported by Goode et al.49a They inject, and subsequently backflow, an aqueous-based fluid containing 2% KC1, diesel oil, a mutual solvent, and a blend of unspecified surfactants.

Lease crude is used in many workover operations. It has the advantages of being cheap and readily available. However, lease crude contains many particulate impurities which may cause impairment,32 just as do particles in "clear"

brines. Crude oil should not, therefore, be used under conditions such that it is liable to invade the formation in significant quantities.

A degradable water-in-oil emulsion is available for use under conditions that require an oil-base fluid with filtration and rheological properties.50 The emulsion droplets are stabilized by a skin of finely divided chalk particles, instead of by organic sufactants. When contacted by acid, the chalk particles dissolve, and the emulsion breaks to oil and water, leaving no residue. The composition is particularly suitable for use in workover wells because it is available in sacked form, which may be mixed with lease crude and water or brine to form the finished emulsion.

Trade names, components, and functions of the various completion and workover fluids available from US and international suppliers have been summarized by Wright.51

Tests for Potential Formation-Damage by Completion Fluids

The complexities of formation damage make it difficult to formulate a non-damaging completion fluid unless extensive laboratory testing is carried out. Such testing necessarily involves considerable expense, both in cutting a core and in the laboratory time involved. However, the costs are miniscule compared with the money saved if the productivity of a newly discovered field is improved by only a small percentage.

One problem—which cannot be completely avoided—is that the core will be altered by contamination by mud particles and filtrate. In some microbit coring tests, Jenks52 et al showed that the filtrate may expel over 50% of the inplace oil. They found that contamination may be considerably reduced by maintaining mud overbalance pressures no greater than 200 psi (14 kg/cm2), and by using muds with low spurt and filtrate losses. Such filtration properties are best obtained with oil muds, which have the additional advantage that their filtrate does not affect water-sensitive clays.

Webb and Haskin53 observed bands of particles from the mud and the formation in cores cut by rubber sleeve and pressure core barrels (see Figure 10-24), but not in cores cut by conventional core barrels.

All cores should be wrapped in plastic sheeting and sealed immediately after recovery. If cores are allowed to dry, indigenous clays become coated with residual oil and the properties of the core are irreversibly altered.54

Laboratory test procedures depend on local conditions and individual preference. A few suggestions that may be of use follow.

Cut the test plugs along the diameter of the core. Then, cut off both ends of ihe plugs at the point where mud contamination is obvious. This procedure will minimize the effect of contamination by the coring fluid, especially if a wide diameter core has been cut.

Figure 10-24. Penetration of mud particles under pressure core barrel. (From Webb and Haskin.53 Courtesy Oi! and Gas J.)

The following preliminary tests will be found useful in planning the testing program:

1. Extract the core with an aromatic solvent; dry, and determine both the permeability to air and the porosity.

2. Make an X-ray analysis to indentify clay minerals, or, at least, make a methylene blue test (see Chapter 3) to evaluate clay mineral activity.

3. On cores from very low permeability reservoirs, make a mercury injection test6 to determine capillary pressures.

4. Analyze a sample of formation water for soluble salts.

Tests for evaluating prospective completion fluids with respect to formation damage should be made on fresh plugs with the interstitial fluids in place. Drying and extracting alters the wettability of the pore surfaces.754 The usual test procedure is as follows:

5. Flow natural or synthetic formation brine through the plugs until constant permeability is obtained.

2. Backflow oil (nitrogen in the case of a gas reservoir) until constant permeability is obtained (A0l).

3. Expose to the test fluid under 500 psi (35 kg/cm2) differential pressure (assuming the fluid has filter-loss control) until at least 1 pore volume of mud filtrate has passed through the core. With a three-inch (7.6 cm) plug, an exposure of a day or so may thus be necessary, unless a dynamic filtration ceil is used.

4. Backflow oil to constant permeability (£„,). The criterion for formation damage is then:

The following tests will be found useful in diagnosing the cause of any impairment that may have been observed, and also in devising remedial measures:

1. To check for the effect of filtrate on indigenous clays without interference by particles from the mud, extract a large volume of filtrate in a multiple filter press, and repea t the above sequence of tests, but flood with the filtrate in step 3 of the flow sequence. Adjust the pressure drop to give an appropriate flow rate, and continue flow until constant permeability is obtained.

2. Check the water saturation after t he initial and final oil flood. If there is a large difference, make imbibition tests7 to determine if there has been a change in wettability.

3. To check for impairment by particles from the mud, extract and dry a plug, then fire at 600°C for at least 6 hours to inactive indigenous clays. Repeat the usual sequence of floods, using the test mud in step 3 of the flow sequence. Any permeability loss then reflects the damage caused by mud particles only. To check the depth of invasion, cut off successive slices of the plug, starting with 0.25 cm, and proceed in 1 cm steps, checking the permeability of the remainder of the plug until it becomes constant. This test should be used in determining the optimum size and amount of bridging particles.

4. Check for mutual precipitation by mixing mud filtrate and formation water.

PACKER FLUIDS AND CASING PACKS Functions and Requirements

When a well is being completed, it is good practice to set a packer between the tubing and the casing above the productive interval, and to fill the annulus with a packer fluid. This procedure is simply a safety measure; when it is not followed, the casing head is subjected to the full reservoir pressure in the case of a dry gas well, and to the reservoir pressure less the column of liquid in the annulus in the case of an oil well. The packer fluid also reduces the pressure differential between the inside of the tubing and the annulus, and between the outside of the casing and the annulus. The density of the packer fluid may or may not be great enough for the column of liquid to balance the tubing pressure at the bottom of the tubing, but even when it does so. there is a pressure differential at shallower depths which increases with decrease in depth.

Since a packer fluid remains in place until it is necessary to do remedial work on the well, which may not be for years, it has certain special requirements which are as follows:

1. It must be mechanically stable, so that solids do not settle on the packer

2. It must be chemically stable under bottom hole temperatures and pressures, so that high gel strengths, which would prevent the mud from being circulated, do not develop.

3. It should contain materials that would seal any leaks that might develop.

4. It must not itself cause appreciable corrosion, and it must protect the metal surfaces from corrosion by formation fluids that might leak into the annulus.

5. Since the perforations will be exposed to the packer fluid in the course of completion and remedial operations, the packer fluid must not damage the formation.

Casing packs are fluids left above the cement in the annulus between the borehole walls and the casing, primarily to protect the casing against corrosion by formation fluids. They may also help control formation pressures, and increase the chances of recovering casing, should the need to do so develop. They must have all the properties of packer fluids, and. in addition, they must have good bridging and filtration properties so as to prevent loss of the fluid pack or its filtrate to permeable formations,

A summary of the properties of the various types of packer fluids and casi ng packs is given below. For detailed recommendations, the reader is referred to an informative paper by Chauvin. 55

Aqueous Packer Fluids Aqueous Drilling Muds as Packer Fluids

Water-based drilling muds that have been used to drill the well are often left in the hole as packer fluids. Advantages are convenience and economy. However, they suffer from the great disadvantage that they are inherently corrosive. Tubing and casing in a producing well are subject to the same reactions that corrode the drill pipe (see Chapter 9 for details), but, whereas in a drilling well, remedial treatments can be applied as often as necessary, treating agents added to a packer fluid must last indefinitely, and there is no assurance that they will do so. Therefore, leaving a water-base drilling mud in the hole as a packer fluid may result in development of casing or tubing leaks in the course of time, and the practice is inadvisable except in wells where corrosive conditions are mild. Also, the mud will solidify over time with temperature, and workover costs can be extremely high.

Low-Solid Packer Fluids

Low-solid packer fluids usually consist of a polymer viscosifier, a corrosion inhibitor, and soluble salts for weight control. Bridging particles, filtration control agents, and sealing materials (such as asbestos fibers) are included if needed. These simple systems are easier to control than high-solid drilling muds. There are no problems with high temperature degradation of lignosul-fonates or clay minerals, and corrosion can be inhibited by oil-wetting agents since the loss of inhibitor is greatly reduced by the low solid content. One unfavorable characteristic is that polymers, being pseudoplastic, have no real yield point, and, with the exception of cross-linked xanthan gum, are not thixotropic. Therefore, particulate solids will slowly settle, but there are so few solids to settle—and no barite—that sedimentation seldom creates difficulties. Another problem is that polymers are to various degrees unstable at elevated temperatures. Long-term stability tests under anticipated bottom hole temperatures should therefore be made on polymer fluids before they are put in the well.

Mayell and Stein56 describe a low-solid packer fluid consisting of attapulgite clay in saturated sodium chloride, with sodium chromate for inhibition of corrosion, and sodium carbonate to raise pH to 10.5. Field tests showed this fluid to have excellent high temperature stability.

Clear Brines

Clear brines may be used as packer fluids, but not as casing packs because they lack filtration control. If they are rigorously filtered and do not become contaminated with drilling mud left on the sides of the tubing or casing, they are virtually solids-free, with all the attendant advantages. Various brines are used as packer fluids, ranging from sea water up to zinc bromide. The decision as to what type and density brine to use is based on several factors, including pressure control, corrosion properties, and cost.

Corrosion is a major concern in designing a packer fluid. In general, brines exhibit low corrosion rates. Except for zinc bromide brines with densities above 18.0 lb/gal, the static equilibrium corrosion rates of various metals in most brines will be less than 10 mils per year (mpy). Unpublished data from various brine suppliers, including Dow Chemical, show that over extended time inter vals up to 300 days, even at temperatures up to 400°F, brines of all types have very low corrosion rates: below 5 to 10 mpy. (Again, the high density brines containing zinc had slightly higher rates: 20-30 mpy.) These rates are for uninhibited brines. Addition of a corrosion inhibitor can yield even lower rates. Inhibitors are generally selected based on the application temperature. Organic chemicals such as amines are used at lower temperature (i.e., below 300°F). Inorganics such as thiocyanates are used for higher temperatures.

Brine Properties

The downhole density of brines, as with any fluid, increases with pressure and decreases with temperature.57,57a,bc The change can be predicted by means of a model developed by Thomas et al.516 Since the effect of pressure is comparatively small, an approximate value of downhole density may be obtained from changes in temperature.57 However, particularly for critical work and in extremely high density, expensive brines, it is advisable to search the literature methods and include the pressure term in the density correction calculation.

Crystallization in surface facilities is sometimes a problem in handling brines. At densities approaching saturation, salts will crystallize out if the temperature falls below a certain critical value, which depends on the composition of the brine 36.57a,b e For example, a 14.8 lb/gal (1.77 SG) CaCl2/CaBr2 brine will crystallize if the temperature of the brine falls below 63°F (17.2°C). Mild crystallization results in deposition of crystals in the surface tanks and lines, with lighter weight brine going downhole. Severe crystallization may cause the entire brine volume to turn to slush or solidify completely.

Oil-Base Packer Fluids and Casing Packs

As discussed in Chapter 9, oil muds are non-corrosive and more thermally stable than water muds. These characteristics make them especially suitable for use as packer fluids, and will usually outweigh their disadvantages of high cost and pollution potential. In deep, hot holes, sedimentation of barite and other solids may become a problem,58 but can be avoided by the addition of an oil-dispersible bentonite.59

Oil-base fluids should be used whenever temperatures are too high for water muds, and whenever corrosion is expected to be severe, e.g., when the formation contains hydrogen sulfide. They make ideal casing packs because of their resistance to corrosion, excellent filtration properties, and also because they facilitate the recovery of casing, should the need to do so arise.00 They are used in the Arctic to replace water base muds from the casing annuli in the permafrost zone.61,62 -6


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