corrosion ct

Tubing Maintenance GuidelinesProcedures to Minimize CT Corrosion

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1. Scope

1.1 Good storage, pre-job and post-job tubing maintenance practices are required to minimizecoiled tubing corrosion and ensure safe and successful completion of coiled tubingservices, as well as maximizing service life of the tubing. Taking the proper steps tominimize corrosion will reduce the probability of unexpected failures and reduce risk topersonnel safety as well as to the customer’s well. It should be recognized that differentlocations may require different procedures but these basic guidelines and recommendationsshould be followed where possible to maximize service life of the coiled tubing string.

1.2 Coiled tubing can be attacked by corrosion externally and internally, either of which can cause premature and unexpected problems and failures. For example, exposure of unprotected coiled tubing to humid atmospheric conditions will produce iron oxide (rust) which can interfere with proper functioning of the injector gripper blocks and well head stripper as well as promote pitting of the coiled tubing. Internal pitting corrosion can be due to untreated aqueous fluids left in the tubing after a job. Taking proper maintenance steps to mitigate corrosion will aid in performance of consistent and successful coiled tubing jobs.

1.3 Underutilized pipe can also create unexpected problems if the pipe is not properly protected during storage. Operations should have realistic inventory plans to insure that there is not excessive tubing in storage. The longer the tubing sits, the more potential there is for corrosion related problems.

1.4 In addition to these guidelines, the operator must be aware of the nature of the downhole conditions and take precautions where appropriate. For example, if H2S is expected, the use of QT-1000 may be prohibited or stress cracking inhibitors may be required.

2. Corrosion and Environmental Cracking of Coiled Tubing - Coiled tubing corrosionconsiderations that operations should be aware of are described below for informationalpurposes. These various forms of corrosion can have several specific detrimental effects oncoiled tubing, such as reduced strength, reduced pressure integrity (collapse and burst), reducedfatigue life as well as an increase in susceptibility to sudden, unexpected premature failures.

2.1 General Corrosion - The result of general corrosion is uniform wall thinning of the coiled tubing. General corrosion is not a common mechanism but may occur when galvanic corrosion (see below) is operative downhole.

2.2 Pitting Corrosion - Pitting can represent a more severe form of corrosion than uniform metal loss. This is due to extensive localized loss of wall thickness which compromises the integrity of the entire string. Low pH (acidic) and higher temperature environments tend to initiate pitting corrosion. Pitting corrosion also occurs in aerated brines under atmospheric conditions. This type of corrosion is a common form of coiled tubing damage and is particularly insidious because pitting creates stress concentration when the tubing is being worked, promoting development of fatigue cracking that could quickly


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lead to a pinhole leak or, worse, complete tubular failure. Since pitting is difficult to detect,effective inhibition and care of coiled tubing is essential.

2.3 Galvanic Corrosion - Galvanic corrosion is not usually a problem when coiled tubing is used in wells containing low alloy steel components. However, in corrosive wells, downhole tubulars may be made of duplex stainless steels, nickel based superalloys or titanium alloys. In contact with an electrolytic fluid, the coiled tubing will become the anode and accelerated corrosion (wall thinning) of the coiled tubing may occur. The effects of general corrosion may be minimized by using chemical inhibition, limiting the exposure time or using thicker wall coiled tubing

2.4 Industrial Atmospheric Corrosion - Sulfur compounds are the major cause of increased corrosion rates in industrial areas. Corrosion will be accelerated in areas of high humidity and warmer temperatures. Time-of-wetness is also a critical variable. Wetness is greater inside the wraps than on top. Water which condenses and is trapped within the tubing wraps as the pipe “breathes” with temperature changes can result in permanent wetness in the wraps. Condensation also occur inside the coiled tubing itself and collect in bottom wraps.

2.5 Marine Corrosion - Corrosion of coiled tubing occurs through contact with marine salts, primarily sodium chloride but also potassium, magnesium, calcium and sulfate ions. Chloride salts are hygroscopic and the chloride ion promotes pitting in coiled tubing steels. Once pitting is established, penetration can occur at accelerated rates. It has been found that steel will corrode 12 times faster when located 80 ft from the coastline than when it is located 800 ft from the coastline, due to the level of marine salts present at the two locations. However, sea salt can be found a great distances from the sea (often as much as 100 miles inland) and can come down both as dry dust and in rainfall. Time-of-wetness is a critical variable in determining the level of corrosion and salt tends to increase time-of-wetness by absorbing water at lower humidities.

2.6 Filiform Corrosion - Filiform corrosion is localized corrosion in the form of randomly distributed filaments or streaks of sharp and long, narrow pits. It can be caused by condensing water solutions containing carbon dioxide, chlorides, sulfates or sulfides. Warm temperatures usually worsen the situation. Elimination of aqueous fluids from the tubing ID will eliminate filiform corrosion.

2.7 Corrosive fluids

2.7.1 Production fluids - Production fluids can be corrosive to coiled tubing if theycontain the acid gases H2S and/or CO2. These gases lower pH of the aqueous phase.Also, production water containing brines increase the overall corrosivity of theproduction fluids. H2S in brine with or without CO2 is more corrosive than H2S inoil. Risk of corrosion or cracking in dry gas wells containing H2S is low. An expertsoftware (CLI International’s Predict, a program for evaluation and determination ofcorrosion in steels) is available for use in predicting the extent of corrosion lossesfrom exposure to reservoir fluids (contact Terry McCoy, memoid ENGZ101).


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2.7.2 Completion fluids - Brines used in workovers and completions increase in corrosivityas temperature increases and as the specific gravity of the brine increases. Aeratedbrines are also more corrosive than deaerated brines.

2.7.3 Acidizing fluids - Acid corrosion inhibitor systems are designed to protect coiledtubing from pitting and unacceptable wall thickness loss under downhole conditions.However, corrosion inhibitors do not impede the ability of the acid to dissolve rust.When the acidized tubing is exposed air (oxygen) back on the surface, then thefreshly cleaned surface now has a significantly increased susceptibility toatmospheric corrosion (rusting), particularly in marine environments. Research hasshown that alternate exposure of coiled tubing to inhibited acid, then air, theninhibited acid, etc. can cause corrosion rates to increase by up to 5 to 7 times thecorrosion rate if exposed only to inhibited acid.

2.7.4 Spent Acid - Because of the depletion and/or dilution of acid inhibitors, spent acidcan be more corrosive than properly inhibited live acid. Flowback acid fromsandstone reservoirs may not be totally spent. Most of the corrosion inhibitor maybe lost to the tubing or formation leaving highly corrosive acid. Also, corrosioninhibitors are blends of components, some of which will adsorb in the formationmore easily than others. The result is that the inhibitor composition in flowbackfluids may not be the same as that originally pumped and its effectiveness may becompromised.

In addition, if the well is underbalanced during acidizing operations, inflow ofreservoir fluids is possible. Formation brine may dilute both the acid and theinhibitor concentration. For example, properly inhibited 15% HCl is not ascorrosive as 5% HCl with 1/3 the original inhibitor concentration, under mostconditions. Also, the produced reservoir fluid and/or gases (such as H2S) maythemselves be quite corrosive and reduce the effectiveness of normal acid corrosioninhibitors.

2.7.5 Nitrogen - Nitrogen generating units (excluding cryogenic nitrogen) can alsogenerate oxygen which will increase corrosion downhole. Membrane generatednitrogen typically contains 2% to 6% oxygen at typical pumping rates. Presence ofdissolved oxygen in water is a major factor influencing corrosion rates on coiledtubing. Even at a temperature of 75°F, water equilibrated with air will contain 7 to8 ppm oxygen and corrosion rates up to 600 mils per year have been measuredunder turbulent conditions. The effects of oxygen on corrosion is magnified byhighly erosive environments.

2.8 H2S Containing Environments - Coiled tubing strength can be reduced by exposure to wetH2S. This occurs when aqueous fluids containing H2S corrode the tubing. The corrosionreaction releases atomic hydrogen which enters the steel matrix potentially causinghydrogen embrittlement of the coiled tubing. The potential for cracking and relatedproblems depends on several factors, such as partial pressure of the H2S, duration of


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exposure, metallurgy of the coiled tubing (chemistry, strength, pre-existing mechanicaldamage, type of welds, etc.), severity of applied stresses and condition of tubing.

QT-700 and QT-800 are suitable for H2S service. Due to its higher strength and hardness,QT-1000 is not usually recommended for sour service as it is more susceptible to hydrogencracking in wet H2S environments than QT-700 or QT-800. However, it should be notedthat QT-1000 has been used in some low H2S sour service situations. Also, use of coiledtubing with butt welds in wet H2S fluids should be avoided if possible as butt welds aremore susceptible to cracking than bias welds. Also, end connectors which are designed toinduce mechanical damage (dimpling, for instance) cause the coiled tubing to be moresusceptible to failure.

When H2S is present in the reservoir, then some judgment must be exercised. For instance,the use of new (or relatively new) tubing may be in order. Also, chemical inhibition maybe required where underbalanced conditions may exist and inflow of H2S is possible. Asan example, in Canada, one location’s general practice is to use an inhibitor whenever H2Sconcentration is 10% or more and contact time is over 8 hours. It may also be advisable touse an inhibitor for lower concentrations of H2S, especially if extended time downhole is apossibility. In these cases, various inhibitors would be used depending on the type of fluidbeing pumped. The inhibitor, in the concentrations listed below, would be circulated fromthe start of the job to protect tubing OD.

ConcentrationInhibitor Treating Fluid (by volume) see note

Crack Chek-97 Produced Fluids0.05 % to 0.20 %Drilling MudOil

SCA-130 Acids 0.4 % to 4 %

Anhib II Mixed Brines 0.1 % to 0.4 %Fresh Water

Note: Also see Chemical Stimulation Manual or HalWeb. Most commonly used range for SCA-130 is 1 % to 2%.

In cases where only nitrogen was being pumped, the inhibitor would be periodically injected into the reel at rates of 1 to 4 liters/hour.

Crack Chek-97 is an inhibitor that is particularly effective for preventing corrosion and sulfide stress cracking of high strength carbon steel in sour brine waters. Note: Never use Crack Chek-97 in acid solutions. SCA-130 was developed for use in acidsolutions.

3. Coiled Tubing Storage Guidelines


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3.1 General - Local conditions must be taken into account when determining the amount of maintenance required to prevent external CT corrosion while tubing is being stored. In warm climates with high humidity, damaging corrosion can occur within a short time and can be especially severe near coastal areas. In dry climates, storage protection requirements may be minimal. Changing conditions during day and night hasten corrosion when temperature of coiled tubing falls below the dew point. Moisture may be trapped for extended periods between the tubing wraps and if chlorides are present, pitting corrosion will be accelerated. For long-term storage, it may be necessary to store the coiled tubing inside and out of the weather. Application of a corrosion inhibitor is still recommended if environmental conditions (temperature and relative humidity) are not controlled and can be damaging. Infrequently used coiled tubing is also subject to internal corrosion and is usually attributed to aqueous solutions remaining is the tubing for extended period of times.

3.2 Covers - Use of weather resistant covers may be helpful in minimizing amount of water and contaminants (such as chlorides from salt spray at sea or in some coastal areas) that the coiled tubing is exposed to and in preventing previously applied inhibitors from being washed off. Unfortunately, covers can also be detrimental to the tubing since they act to trap moisture (condensation) and not let the tubing “breathe”, even if the bottomof the cover is open. Covers are not the answer to external coiled tubing corrosion problems but may be useful in some limited situations.

3.3 Freeze Protection - Although the tubing should be free of water during storage, there is always the possibility of unintended residual moisture in the tubing string. If the tubing is to be stored at a location where temperature is expected to drop below the freezing point, then it may be advisable to pump an antifreeze (ethylene glycol) mixture through the string. Commerciallly available antifreeze has the added advantage of containing corrosion inhibitors.

Expected Lowest RecommendedTemperature (°F) Concentration in water

-10 40%-20 44%-30 48%-40 52%-50 56%

3.4 Bedwrap Protection - Initial external protection of the bedwrap tubing is recommended when CT is used in warm, humid coastal areas. The following inhibitors are recommended, in order of expected performance. Other inhibitors may be satisfactory. Note: No Halliburton part numbers have been assigned to these products but may in the future if usage warrants.

Approximate


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Inhibitor Relative Cost

PermaStopRust’s Isotrol/Isoguard 1 (Best) 33Cortec’s VCI-386 2 6Nalco/Exxon’s CT-Armor 3 (neat) 2Exxon’s Rust Ban 343 4 1

On storage or shipping reels, the inhibitor could be applied when the tubing is spooled onto the working reel. Quality Tubing expects that Rust Ban 343 is a suitable inhibitor to protect coiled tubing during shipments to North America locations with expectations that tubing would not be stored over 30 days. VCI-386 is thought to be suitable for export shipments. No significant loss in injector force capabilities is expected when using the above inhibitors, however, it should be cautioned that no field trials have been conducted at this time on the Isotrol/Isoguard or VCI-381. Rust Ban 343 has a proven field record for internal storage conditions. To date, only lab tests have been run on the other inhibitors.

3.5 Tubing OD Protection - When required (also see paragraph 6), apply a corrosioninhibitor to the tubing OD after each job. Inhibitor should be applied to the tubing bywiping to ensure complete coverage of the tubing. (Note: a wiping mechanism is currentlybeing developed). Recommended corrosion inhibitors are shown below, in order ofexpected performance. Other inhibitors may be satisfactory. The tubing should be asclean as possible for maximum effectiveness of the inhibitor. Note: No Halliburton partnumbers have been assigned to these products but may in the future if usage warrants.

ApproximateInhibitor Relative Cost

Cortec’s VCI 386 (Best) 6Nalco/Exxon’s CT-Armor (neat) 2

Oil Research Center’s Wireline Spray 782 5 1.5Exxon’s Rust Ban 343 1

Note: Wireline Spray 782 is the only environmentally friendly, completely biodegradable corrosion inhibitor listed above. Corrosion testing seemed

to indicate that the inhibitor would perform well for a few weeks then performance would decrease at a more rapid rate with time.

Note: Nalco/Exxon’s CT-Armor is most effective in neat (concentrated) form. It can be used diluted (10% in water) but when applied, the inhibitor must be continually mixed to insure proper inhibitor coverage. CT-Armor is water dispersible but not water soluble.


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3.6 Tubing ID Protection (also see notes below).

Option 1• Use dry nitrogen to displace specific volume of 10% CT-Armor (1 part CT-

Armor and 9 parts fresh water) through the tubing to achieve a 3 mil coatingthickness. Inhibitor should be pumped behind wiper ball(s) if another fluid isbeing displaced (see note 1). The solution must be continually mixed as thefluid is pumped into the tubing as CT-Armor is water dispersible but notwater soluble. See Table 1 for recommended volume of inhibitor needed tocoat tubing ID.

• Seal ends of tubing to prevent loss of inhibitor or air ingression (see note 2).

Option 2

• Pump fresh water that has been adjusted to a pH 8 to 9 using sodiumbicarbonate and that is also treated with 0.2% Anhib II (HES part number516.00854). Displacing volume should be a minimum of 2 times tubingvolume. If chlorides are to be removed, then displacing volume should be 5times tubing volume. Proper mixing is required to insure that Anhib II is welldispersed in the fluid.

• Purge with nitrogen until dry and seal ends (see notes 2 and 3).

Option 3• Fill tubing with diesel fuel. A good grade of diesel fuel (such as No. 2

automotive diesel) should be used to avoid possibility of water contamination.If residual water is in the tubing prior to filling with diesel, it may get mixedin with the diesel (causing a cloudy appearance) and will separate out in thetubing causing corrosion to occur. If diesel fuel is used, it is recommendedthat at least one (1) quart of API 30 wt. motor oil be used per 100 gallons ofdiesel. The oil has alkalinity as well as corrosion inhibitors that will helpprotect the coiled tubing.

Note 1: Wiper Balls - whenever displacing tubing containing fluid(s), a tightpolyurethane wiper ball or dart or should precede the pumped fluid. The wiper ball aids inthe effectiveness of its “chaser” by (1) separating the different fluids preventingintermixing and (2) wipes the tubing walls from the preceding fluid. If gas is being used topush a fluid through the coiled tubing, use at least 2 wiper balls. The following guidelinescan be used in choosing the proper size of wiper ball.

Wiper BallTubing OD Diameter1.00” 1-1/4”1.25” 1-1/2”


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1.50” 2” (for thick wall, use 1-3/4”)1.75 2-1/4”2.00” 2-1/2”2.375” 2-3/4”2.875” 3-1/4”3.50” 3-7/8”

Wiper balls can be purchased from Laser Plastics, 903 Hodgkins, Suite #103, Houston,TX. 77032 (Tel: 281-590-0566; Fax: 281-590-8174). If standard wiper balls are notavailable, a tightly made wad of foam rubber (seat cushion type of material) may be used.

Note 2: Sealing Ends of Pipe - When using nitrogen in tubing to prevent corrosion, theends of the tubing must be sealed such that a slight positive pressure (say, 5 to 10 psig) ismaintained to prevent air ingression. For information purposes, Quality Tubing’s presentprocedure is to place a Drilltec thread protector on the male half of 1502 fittings on allnitrogen purged strings. On the free end, a plastic or metal cap is placed on the tubingand taped. Quality Tubing also offers a system to install a ball valve on each end oftubing with a pressure gage to monitor internal pressure. This systems requires fittings onboth ends of tubing.

Note 3 - Purging Water from Coiled Tubing with Nitrogen - Displacement of fluidssuch as water from a coil tubing reel after a job is critical to the life of the pipe and thesafe operation of the unit. In general displacement with nitrogen to remove water takes twosteps. The first is to remove the free water. This is accomplished by pumping nitrogen at ahigh rate to mobilize and remove all free water. Use of wiper balls to remove the water isrecommended (see note 1). The second step is to dry the film of fluid that remains.Drying works best at low pressure. This means pumping as slow as possible to keep thefriction pressure down.

Volume of nitrogen required is a function of tubing volume. Each barrel of tubing volumerequires 1000 scf of nitrogen to displace and dry the pipe. An example would be displacinga reel that has 10 bbls of fluid. Volume of nitrogen required would be 10 x 1000 = 10,000scf. Initial rate would be 400 to 1000 scf/min. When nitrogen breaks through, decrease therate to 100 to 400 scf/min. Larger size tubing will require the higher range of rates whilesmaller tubing will require the lower rate. See Best Practices Series “Purging Fluids fromCoiled Tubing” for other information.

4. Pre-Job Guidelines - If unsure of the condition of the tubing ID, flush coil tubing with freshwater. If the water in the exit stream is clear, then the coiled tubing ID probably has beensufficiently protected during previous storage and no further fluid maintenance work is required.If significant rust is present in the initial portion of the exit stream then the condition of thetubing ID should be questioned. If necessary, the ID can be pickling with 5 % HCl + 0.1 %HAI-81M + 2 % Ferchek.


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5. Post-Job Guidelines

5.1 Tubing OD - refer to paragraph 3.5.

5.2 Tubing ID

5.2.1 Acid - After acid jobs, the tubing should be treated as per one of the options listed below. Research indicates that coiled tubing does not undergo excessive corrosion when exposed to properly inhibited acid being pumped at treatment velocities. However, laboratory tests on tubing exposed to inhibited acid and air indicate that oxygen is a

secondary corrosive agent and can cause corrosion rates to increase 5 to 7 times that in acid alone. Aeration occurs between jobs so it is important that the tubing be cleaned and protected with a corrosion inhibitor as soon as possible after an acid job.

Option 1• Flush with fresh water (or seawater when necessary). Continue flush until

pH of exit stream is approximately 7.• Displace with water adjusted to pH 8 to 9 using 1% K-34 (sodium

bicarbonate, HES part number 70.15186) and 0.20% Anhib II (HES partnumber 516.00854).

• Purge with nitrogen (see note 3, paragraph 3.6) until tubing is dry, then sealends.

Option 2• Neutralize/flush acid remaining in tubing using 1% K-34 (sodium bicarbonate,

HES part number 70.15186).• Flush with fresh water.• Displace fresh water with 10% CT-Armor. Use dry nitrogen to push the

inhibitor mixture through the tubing. See Table 1 for recommended volumesfor specific tubing sizes.

• Seal ends of tubing to prevent inhibitor loss or air ingression.

Option 3 - MB TechServ 6 - This is a specialized process used by Quality Tubing’s service center in Aberdeen. This process has not been utilized in other locations. For further information, contact Brian Hunt, MB TechServ at 44-1224-879696.

• Flush - Remove debris, acid, brine, etc. by flushing coiled tubing with freshwater (onshore) or seawater (offshore) immediately after use. If available,purge with nitrogen (see note 3, paragraph 3.6) to displace excess water.

• Clean (onshore) - Flush with fresh water to remove seawater and anycorrosive contaminants. Pig with wiper ball(s) and purge with nitrogen toremove residual water.


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• Dry (onshore) - Connect MBT injection unit (see note below) with 120 psicompressed and filtered air supply to the coiled tubing. Establish constantflow of dry air through coil to remove residual moisture. Allow coil todepressurize fully to atmosphere.

• Preserve (onshore) - Charge MBT with VCI 609 powder. Release charge tothe coiled tubing until fog emission is detected. Allow coil to depressurizefully then seal ends.

5.2.2 Workover and Completion fluids - These fluids may be corrosive to the coiled tubing and should be removed before the tubing is stored.

Option 1• Flush with fresh water.• Displace with water adjusted to pH 8 to 9 using 1% K-34 (sodium

bicarbonate, HES part number 70.15186) and 0.20% Anhib II (HES partnumber 516.00854).

• Purge with nitrogen (see note 3, paragraph 3.6) until tubing is dry, then sealends.

Option 2• Flush with fresh water.• Displace fresh water with 10% CT-Armor. Use dry nitrogen to push the

inhibitor mixture through the tubing. See Table 1 for recommended volumesfor specific tubing sizes.

• Seal ends of tubing to prevent inhibitor loss or air ingression.

Option 3 - MB TechServ• Same as above.

5.2.3 H2S - If the tubing contains iron sulfide scale, pickling with 5% HCl + 0.40 - 2.0% SCA-130 (concentration of SCA-130 dependent on the amount of FeS in the tubing) may be necessary to clean the tubing. Caution: This process may generate H2S gas in the tubing. After pickling, follow paragraph 5.2.1 options as needed.

6. Maintenance Recommendations - Special Cases - Although frequency and type ofmaintenance depends on local conditions as well as frequency and type of service work, thefollowing are some recommendations for consideration. Ideally, each local service centershould have documented procedures to follow.


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6.1 Tubing being used daily in non-corrosive service (considering both atmospheric as well as downhole and pumped fluids) probably does not need to be treated daily with

corrosion inhibitors.

6.2 Tubing stored or not expected to be used for 1 week or longer should be suitably protected on the ID and OD.

6.3 Tubing used in acid service should be treated immediately upon job completion. Refer to paragraph 5.2.1.


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Table 1

Gallons of 10% CT-Armor

Tubing Flash In Flash Free

OD X Wall Gallons per1000 ft

Gallons per1000 ft

1.00 X .080 4.26 4.11

1.00 X .087 4.21 4.04

1.00 X .095 4.14 3.97

1.00 X .102 4.09 3.90

1.00 X .109 4.03 3.83

1.25 X .080 5.49 5.34

1.25 X .087 5.43 5.27

1.25 X .095 5.37 5.19

1.25 X .102 5.31 5.12

1.25 X .109 5.26 5.05

1.25 X .125 5.13 4.90

1.25 X .134 5.06 4.81

1.25 X .156 4.88 4.59

1.50 X .095 6.59 6.41

1.50 X .102 6.54 6.34

1.50 X .109 6.48 6.28

1.50 X .125 6.35 6.12

1.50 X .134 6.28 6.03

1.50 X .156 6.11 5.82

1.75 X .109 7.70 7.50

1.75 X .125 7.58 7.34

1.75 X .134 7.51 7.26

1.75 X .156 7.33 7.04

1.75 X .188 7.08 6.73

2.00 X .109 8.93 8.72

2.00 X .125 8.80 8.57

2.00 X .134 8.73 8.48

2.00 X .156 8.56 8.26

2.00 X .175 8.41 8.08

2.00 X .188 8.30 7.95

2.00 X .203 8.18 7.80

2.375 X .109 10.76 10.56

2.375 X .125 10.64 10.40

2.375 X .134 10.57 10.32


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Table 1

Gallons of 10% CT-Armor

Tubing Flash In Flash Free

OD X Wall Gallons per1000 ft

Gallons per1000 ft

2.375 X .156 10.39 10.10

2.375 X .175 10.24 9.91

2.375 X .188 10.14 9.79

2.375 X .203 10.02 9.64

2.875 X .125 13.08 12.85

2.875 X .134 13.01 12.76

2.875 X .156 12.84 12.55

2.875 X .175 12.69 12.36

2.875 X .188 12.59 12.23

2.875 X .203 12.47 12.09

3.50 X .156 15.90 15.82

3.50 X .175 15.75 15.42

3.50 X .188 15.65 15.29

3.50 X .203 15.53 15.15


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References:

1 PermaStopRust (America), Inc. 2911 Dixwell Avenue Hamden, CT 06518 Tel: (800) 611-7713 (203) 287-3700 Fax: (203) 407-3840

2 Cortec Corporation 4119 White Bear Parkway, St. Paul, MN 55110 Phone: (800) 4-CORTEC (612) 429-1100 Fax: (612) 429-1122

3 Nalco-Exxon Energy Chemicals, L.P. 7705 Hwy 90A Sugar Land, TX 77478 P.O. Box 87 Sugar Land, TX 77487-0087 Phone: (713) 263-7836

4 Exxon Company USA P.O. Box 2180 Houston, TX 77252-2180 Tel: (713) 656-5949

5 Oil Research Center 626 W. Pont Des Mouton Road Lafayette, LA 70507-4002

6 MB TechServ Corrosion Technology Services, Ltd. 38 Abbotswell Road Aberdeen, AB12 3AB Tel: (01224) 879 696 Fax: (01224) 899 180

corrosion ct

Documents

halliburton part numbers

specific tubing sizes

minimize ct corrosion

prevent inhibitor loss

protect coiled tubing

displace fresh water

crack chek

wiper ball