NACE RP0775-99
Standard
Recommended Practice
Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield
Operations
This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he has adopted the standard or not, from manufacturing, marketing,purchasing, or using products, processes, or procedures not in conformance with this standard.Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus,or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers.
Users of this NACE International standard are responsible for reviewing appropriate health,safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard.
CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International Membership Services Department, P.O. Box 218340, Houston, Texas 77218-8340 (telephone +1 (281)228-6200).
Revised 1999-06-25Revised 1991Revised 1987Approved 1975NACE International P.O. Box 218340
Houston, Texas 77218-8340
+1 (281)228-6200ISBN 1-57590-086-6NACE Standard RP0775-99
Item No. 21017
RP0775-99
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Foreword
This standard recommended practice was prepared to encourage the use of uniform and industry-
proven methods to monitor mass-loss and pitting corrosion in oilfield operations. This standard
outlines procedures for preparing, installing, and analyzing metallic corrosion coupons. Factors
considered in the interpretation of results obtained from these corrosion coupons are also
included for the use of oil and service industry personnel.
This standard was originally prepared in 1975 by NACE Task Group T-1C-6, a component of Unit
Committee T-1C on Detection of Corrosion in Oil Field Equipment, to provide procedures for the preparation, installation, and analysis of corrosion coupons. The standard was revised by Task
Group T-1C-11 in 1986 and by T-1C-23 in 1991. T-1C was combined with Unit Committee T-1D
on Corrosion Monitoring and Control of Corrosion Environments in Petroleum Production Operations, and this standard was revised by Task Group T-1D-54 in 1999. It is issued by NACE International under the auspices of Group Committee T-1 on Corrosion Control in Petroleum Production.
In NACE standards, the terms shall, must, should, and may are used in accordance with the
definitions of these terms in the NACE Publications Style Manual, 3rd. ed., Paragraph 8.4.1.8.
Shall and must are used to state mandatory requirements. Should is used to state that which is considered good and is recommended but is not absolutely mandatory. May is used to state that
which is considered optional.
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RP0775-99
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NACE International
Standard
Recommended Practice
Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations
Contents
1.General (1)
2.Processing of Corrosion Coupons (2)
3.Installation of Corrosion Coupons (5)
4.Recording Data on Corrosion Coupon Report (14)
5.Interpretation of Corrosion Coupon Data (14)
References (15)
Appendix A—Typical Corrosion Coupon Report (16)
Figure 1—Circular (washer-type) coupon and typical mounting in a ring joint flange (6)
Figure 2—Drill pipe corrosion ring coupon (7)
Figure 3—Flat coupon holder using a 50-mm (92-in.) pipe plug (8)
Figure 4—Round (rod-type) coupon holder using a 50-mm (2-in.) pipe plug and special insulating disk that can accommodate eight round (rod-type) coupons (9)
Figure 5—Tool for installing and removing coupons in systems under pressure (10)
Figure 6—Extractor tool for inserting and removing coupons in systems under pressure10
Figure 7—Wire-line-operated tubing stop adapted as downhole coupon holder (12)
Figure 8—What can occur at changes in direction and elevation in a wet gas system..13
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RP0775-99 _______________________________________________________________________
Section 1: General
1.1This standard is presented for the use of corrosion coupons in oilfield drilling, production, and transportation operations. Oilfield operations include oil-, water-, and gas-handling systems, and drilling fluids. (When used in this standard, system denotes a functional unit such as a producing well; flowline and tank battery; water, oil, or gas collection facility; water or gas injection facility; or a gas dehydration or sweetening unit.) Corrosion coupon testing consists of the exposure of a small specimen of metal (the coupon) to an environment of interest for a period of time to determine the reaction of the metal to the environment. Corrosion coupons are used to eval-uate corrosiveness of various systems, to monitor the effectiveness of corrosion-mitigation programs, and to evaluate the suitability of different metals for specific systems and environments. The coupons may be installed in the system itself or in a special test loop or apparatus. Corrosion rates shown by coupons and most other corrosion-monitoring devices seldom duplicate the actual rate of corrosion on the system piping and vessels. Accurate system corrosion rates can be determined by nondestructive measurement methods or failure fre-quency curves. Data furnished by corrosion coupons and other types of monitors must be related to system requirements. High corrosion rates on coupons may be used to verify the need for corrective action. If a corrosion-mitigation program is initiated and subsequent coupon data indicate that corrosion has been reduced, the information can be used to approximate the effectiveness of the mitigation program. This standard does not contain information on monitoring for inter-granular corrosion, stress corrosion cracking (SCC), or sulfide stress cracking (SSC). The latter aspects are discussed elsewhere.(1),(2)
1.2This standard describes preparation and handling techniques for metal coupons prior to and following exposure. Corrosion rate calculations and a typical form for recording data are also included.
1.3Coupon size, metal composition, surface condition, and coupon holders may vary according to the test system design or the user’s requirements. Coupons are often installed in pairs for simultaneous removal and average mass-loss determination. Coupons may be used alone but they should be used in conjunction with other monitoring methods such as test nipples, hydrogen probes, galvanic probes, polarization instruments, resistance-type corrosion monitors, chemical analysis of process streams and nondestructive metal thickness measurements, caliper surveys, and corrosion failure records.
1.4Corrosion coupons used as suggested in this standard measure the total metal loss during the ex-posure period. They show corrosion that has already occurred. A single coupon cannot be used to determine whether the rate of metal loss was uniform or varying during the exposure period. Information on the change in corrosion rate can be obtained by installing several coupons at one time and removing and evaluating individual coupons at specific short-term intervals. Other monitoring methods mentioned in Paragraph 1.3 can be used to provide more accurate information on short-term rates of corrosion. Data provided by corrosion coupons can provide excellent back-up for “event-indicating”corrosion-monitoring instruments.
1.5In addition to mass loss, important factors to con-sider in the analysis and interpretation of coupon data include location, time on-stream, measured pit depth, surface profile (blistering, erosion), corrosion product and/or scale composition, and operating factors (e.g., downtime, system flow velocities, upsets, or inhibition). 1.6Coupon corrosion rates in one system should not be compared directly with those in other unrelated systems. However, corrosion rates in similar systems (e.g., two systems handling identical environments) often correlate. Additional information can be obtained within a system by varying one exposure parameter at a time (e.g., location or duration of exposure). For example, corrosion rates can be affected by changes in fluid velocity within a system. Corrosion rates can vary dramatically upstream and downstream from the point of entry of a corrodent, such as oxygen.
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(1) NACE Standard MR0175 (latest revision), “Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment,” (Houston, TX: NACE International).
(2) E.M. Moore, J.J. Warga, “Factors Influencing the Hydrogen Cracking Sensitivity of Pipeline Steels,” CORROSION/76, paper no. 144 (Houston, TX: NACE, 1976).
RP0775-99
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Section 2: Processing of Corrosion Coupons
2.1Coupon Preparation. The following procedure should be used to prepare coupons for corrosion testing. Coupons should be new; do not re-use coupons after exposure and analysis.
2.1.1Choose a method of coupon preparation that
does not alter the metallurgical properties of the metal. Grinding operations must be controlled to avoid high surface temperatures that could change the microstructure of the coupon.
2.1.2Etch or stamp a permanent serial number on
the coupon. It is possible for a coupon or holder to undergo SCC if the conditions in Paragraphs 2.1.2.1 and 2.1.2.2 are met:
2.1.2.1Exposure to an environment capable of
cracking the alloy used for the coupon or holder.
2.1.2.2Stress sufficiently high to cause crack-
ing. Such stress can result from a combination
of residual stress (such as introduced by
stamping) and imposed stress.
2.1.2.3Instances of SCC of carbon steel
coupons under oilfield conditions have rarely
been reported. Nevertheless, broken pieces of
coupons or holders can lodge downstream in
valves and interfere with their normal operation.
2.1.3Machine or polish the edges of the coupon to
remove cold-worked metal if the cold-worked edges adversely affect the data. Coupons formed by stamping are less expensive than machined cou-pons. Stamped coupons are satisfactory without additional machining for most oilfield monitoring.
2.1.4Ideally, match the surface finish of the
coupons with the finish of the metal being invest-igated, i.e., the pipe or vessel wall. Because this is seldom practical, other surface finishes are applied.
No specific surface finish is absolutely essential but uniformity is very important when data from different sets of coupons are being compared. Coupons may be prepared by grinding smooth with 120 grit paper, by tumbling with loose grit, or blasting with abrasive blasting material. A consistent finish may be ob-tained by blasting with glass beads, but glass beads may not remove mill scale or rust. All abrasives should be free of metallic particles.
2.1.5After the coupons have been cleaned, handle
them by suitable means to prevent contamination of the surface with oils, body salts, and other foreign materials. Clean, lint-free cotton gloves or cloths, disposable plastic gloves, coated tongs, or coated tweezers should normally be used.
2.1.6Under a ventilated hood, remove any residual
oils with a hydrocarbon solvent such as xylene, toluene, or 1,1,1 trichloroethane and rinse with an-hydrous isopropyl alcohol. If oils are not present, cleaning with alcohol or acetone should be sufficient.
2.1.7Dry, measure, and weigh the coupons to within
±0.1 mg. Record the mass, serial number, and exposed dimensions. Calculate the surface area (including the edges) and record. The areas covered by the coupon holder and shielded areas of flush-mounted coupons must be excluded. (For test nipples or other large corrosion test pieces, see Paragraph 3.6.)
2.1.8Prior to shipment, store the individually pack-
aged coupons in a closed container with indicating silica gel.(3) Coupons may be wrapped in paper or placed in envelopes impregnated with a vapor-phase corrosion inhibitor.
2.2Procedure for Field Handling of Coupons Before and After Exposure
2.2.1Prior to coupon installation, record the
following information: coupon serial number, install-ation date, name of system, location of the coupon in the system (including fluid or vapor phase), and orientation of the coupon and holder. A typical corrosion coupon report is shown in Appendix A.
2.2.2During installation, handle the coupon carefully
to prevent contamination of the coupon surface. (See Paragraph 2.1.5.)
2.2.3When the coupon is removed, record the
coupon serial number, removal date, observations of any erosion or mechanical damage, and appearance of scale or corrosion product. Any other pertinent data such as shut-in time and changes in velocity and inhibitor treatment should also be recorded.
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(3) Silica gel that has become inactive as a result of moisture absorption can be reactivated by heating in an open metal pan in an oven at 119 to 127°C (246 to 261°F) for at least 12 h. Reactivated silica gel must be stored in an airtight container. Indicating silica gel impregnated with cobaltous chloride changes color when it becomes saturated with moisture.
RP0775-99
The coupon should be photographed immediately after removal, particularly if appearance of the corrosion product or scale is important.
2.2.4Protect the coupon from contamination by
oxidation and handling. Place the coupon in a moisture-proof or special envelope impregnated with volatile corrosion inhibitor and ship immediately to a laboratory for analysis. Do not coat the coupon with grease or otherwise alter it. Gentle blotting with tissue paper or a clean soft cloth may be desirable to remove moisture prior to shipment. Corrosion products or scale deposits should not be removed in the field.
2.3Laboratory Procedure for Cleaning and Weighing Coupons After Exposure
2.3.1Record the coupon serial number. If the
coupon was not photographed in the field, it should be photographed in the laboratory before and after cleaning. Prior to any cleaning, weigh the coupon to within ±0.1 mg.
2.3.2Visually examine the coupon and record
observations. Qualitative analysis of adherent scale or foreign material may be performed.
2.3.3Immerse the coupon in a suitable hydrocarbon
solvent, such as clean xylene or toluene, long enough to remove the oil, oil-wet materials, and paraffin. Rinse with isopropyl alcohol or acetone.
Handle solvent under a ventilated hood. Dry in a gentle dry air stream and weigh the coupon to within ±0.1 mg if quantitative analysis of acid-soluble deposits is desired.
2.3.4Immerse steel coupons in 15% inhibited
hydrochloric acid to remove mineral scale and corrosion products. Ultrasonic agitation may be used to accelerate the cleaning process. Numerous commercial inhibitors are available to protect the steel during acid cleaning. The following inhibitor solution has been successful: A stock solution is made of 37.5% HCl to which 10 g/L of 1,3-di-n-butyl-
2 thiourea (DBT) has been added.1 Immediately prior
to use, the stock solution is diluted by slowly adding
a measured volume of stock solution to an equal
volume of distilled water with stirring. Additional information on cleaning metals other than steel should be consulted.2,3,4
2.3.4.1Coupons that are not coated with hard
scale or tightly adhering corrosion products may
be cleaned by blasting with glass beads. Mass
loss during blast cleaning should be determined
by cleaning unexposed coupons in accordance
with Paragraph 2.3.7.
2.3.5After cleaning, immerse the coupon in a
saturated solution of sodium bicarbonate for one minute to neutralize the acid. Rinse with distilled water to remove the neutralizer.
2.3.6Rinse the coupon immediately in isopropyl
alcohol or acetone and dry in a stream of dry air. Air lines should be equipped with traps and filters to remove all oil and water. Coupons with tenacious films should be scrubbed with a household cleanser and 000 steel wool prior to drying with alcohol or acetone. Visually examine the coupon and record observations.
2.3.7Subject a preweighed blank that was not
exposed to the corrodent to the cleaning process to ensure that mass loss from cleaning is not significant.
2.4Calculation of the Average Corrosion Rate (CR). The following procedures should be used to calculate the average corrosion rate.
2.4.1Determine the mass loss of the corrosion
coupon and divide the mass loss by the product of the metal density (Table 1), the total exposed surface area, and the exposure time to obtain the average rate of corrosion. The following equations may be used to determine the average corrosion rate depending on the units desired.4
2.4.1.1A calculation of average corrosion rate,
expressed as a uniform rate of thickness loss
per unit time in millimeters per year or
millimeters per annum (mm/y or mm/a), is
shown in Equation (1):
ATD
W
x
10
x
3.65
=
ATD
1,000
x
365
x
W
=
CR
5
(1)
CR = average corrosion rate, millimeters per
year (mm/y or mm/a)
W = mass loss, grams (g)
A = initial exposed surface area of coupon,
square millimeters (mm2)
T = exposure time, days (d)
D = density of coupon metal, grams per cubic
centimeter (g/cm3)
2.4.1.2A calculation of average corrosion rate,
expressed as uniform rate of thickness loss per
unit time in mils per year (mpy), is shown in
Equation (2):
ATD
W
10
2.227x
=
(2.54)
x
ATD
1,000
x
365
x
W
=
CR
4
3
(2)
RP0775-99
CR = average corrosion rate, mils per year
(mpy)
W = mass loss, grams (g)
A = initial exposed surface area of coupon, square inches (in.2)
T = exposure time, days (d)
D = density of coupon metal, grams per cubic centimeter (g/cm3)
2.4.1.3A calculation of the average corrosion rate, expressed as a uniform rate of mass loss per unit area per unit time in grams per square meter per day (g/m2/d), is shown in Equation (3):
T
x
A
W
=
CR(3)
CR = average corrosion rate, grams per square meter per day (g/m2/d)
W = mass loss, grams (g)
A = initial exposed area of coupon, square meters (m2)
T = exposure time, days (d)
Table 1 — Density of Metals(A)
Material Density, g/cm3Material Density, g/cm3
Cast Irons Copper Alloys
Gray cast iron7.15Admiralty brass8.53
Malleable iron7.27Red brass, 85%8.75
Yellow brass8.47
Steels Bronze—5% Aluminum8.17 Carbon steel7.86Bronze-Phosphor 10%8.78
Low-alloy steels7.85Copper-Nickel (90-10)8.84
9 Cr-1 Mo7.67Cast Al-Bronze7.80
5 Ni7.98Beryllium Copper8.35
9 Ni8.10
Other Materials
Stainless steels Aluminum 2.70 Type 3047.90Magnesium 1.74
Type 3168.00Nickel8.90
Types 321, 3478.02Zinc7.13
Type 4107.70
13 Cr7.70
17-4 pH7.80
22 Cr-5 Ni (duplex)7.89
(A) Alloys are wrought unless otherwise noted. (Source: ASM Handbook, Vol. 1, Properties and Selection: Irons, Steels, and High-Performance Alloys, 10th ed., 1990, ASM International, 9639 Kinsman Rd., Materials Park, OH 44073-0002).
RP0775-99
2.4.1.4A calculation of the average corrosion rate, expressed as a uniform rate of mass loss per unit area per unit time in pounds per square
foot per year (lb/ft 2
/y), is shown in Equation (4):
AT
10 x 1.159 x W
= 453.6 x AT 144 x 365 x W = CR 2
(4)
CR = average corrosion rate, pounds per square
foot per year (lb/ft 2
/y)
W = mass loss, grams (g)
A = initial exposed area of coupon, square
inches (in.2
)
T = exposure time, days (d)2.4.1.5Conversion Factors
6,7,8
1 mm/y = 39.4 mpy
1 μm/y = 0.0394 mpy (μm = micrometer)1 mpy = 0.0254 mm/y
1 mpy = 0.001 in./y (inches per year)1 mil = 0.001 in.
2.5Calculation of the Maximum Pitting Rate (PR). The following procedure should be used to calculate the maximum pitting rate.
2.5.1Determine the depth of the deepest pit and divide by the exposure time. The following Equations (5) and (6) may be used to determine the maximum pitting rate depending on the units desired.
(days)
time exposure 365
x (mm) pit deepest of depth
= (mm/y) PR (5)
(days)
time exposure 365
x (mils) pit deepest of depth
= (mpy) PR (6)
2.5.2Pit depths may be measured with a depth gauge or a micrometer caliper with needle-point anvils. The anvil must be small enough to reach the bottoms of the pits. An optical microscope calibrated for depth measurement may also be used to estimate pit depth. The microscope should be focused first on uncorroded metal adjacent to the pit and then focused on the bottom of the pit. Metallographic cross-sections through pits provide an accurate measurement of pit depth if a high degree of accuracy is deemed necessary. The same measure-ment technique should be used on all coupons from a given system. Pit density per unit area should be reported. Additional information on the measure-ment of pits can be found in ASTM (4) G 46.
9
2.5.3Pitting characterization by calculation of pitting rate may be misleading if pitting onset occurs after an incubation period. Time to pitting onset varies and pit growth may not be uniform. Therefore, care should be exercised in applying calculated pitting rates to project time-to-failure.
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Section 3: Installation of Corrosion Coupons
3.1Types of Corrosion Coupons
3.1.1Corrosion coupons are available from a number of suppliers. Coupons are available in many different sizes and configurations. The size and configuration selected depend on the type of holder being used, line size, and entry orientation. Special access fittings and devices that allow installation and retrieval under pressure may require a specific type of coupon. It is usually advantageous to standardize a few sizes to minimize inventories and to eliminate difficulties in preparation and handling.
3.1.2Circular (washer-type) coupons shown in Figure 1 are available in various sizes. The size of the circular coupon, which fits between a pair of ring
joint flanges, depends on the size and type of flange in which the circular coupon is to be installed.3.1.3Ring-type coupons for use in drill pipe tool joints are shown in Figure 2. Additional information
on the use of drill pipe coupons can be found in API
(5)
RP 13B-1.
10
3.1.4Corrosion coupons can be modified for studies of oxygen concentration cells. A rubber band can be placed around the coupon, excluding oxygen from
the metal under the rubber band.11
An oil-resistant elastomer should be used if hydrocarbons are present. Banded coupons should not be used for mass-loss determinations. Coupons banded in this manner are not practical in high-velocity streams.
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(4) American Society for Testing and Materials (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959.(5)
American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005.
RP0775-99
3.2Coupon Composition
3.2.1Coupons are usually made of 0.1 to 0.2%carbon steel that is readily available in strip and plate form and is easily worked. Depending on the reason for testing, metals used should normally be identical to those in the system, but may also include metals and alloys that are being considered for use in the system.3.3Coupon Holders
Coupon holders are available in many sizes and shapes to hold one or more flat or round (rod-type) coupons.Some common holders are shown in Figures 3 and 4.
3.3.1Depending on the system, corrosion coupons may be mounted in a variety of ways. Mounting must accomplish the following:
3.3.1.1Adequate support of the coupons in the
system.
FIGURE 1 — Circular (washer-type) coupon and typical mounting in a ring joint flange.
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3.3.1.2Electrical isolation of the coupon from other coupons, from the coupon holder, and from the pipe or vessel wall, to prevent galvanic corrosion.
3.3.1.3Maintenance of the coupon’s position in the desired location and positioning it in the system (i.e., either in the fluid or vapor phase,perpendicular or parallel to the flow stream).
3.3.1.4Provision for easy and rapid changing of coupons in the field.
3.3.2Coupon holders like the one shown in Figure 3should be marked so the coupon orientation can be determined when it is in service. (See Paragraph 3.
4.6.)
3.3.3The system must be depressurized prior to installation and removal of the coupons and holders
shown in Figures 3 and 4.
FIGURE 2 — Drill pipe corrosion ring coupon: (a) steel corrosion ring (fabricated in accordance with API
RP 13B-1); (b) steel corrosion ring coupon encapsulated in plastic; and (c) installed.
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FIGURE 3 — Flat coupon holder using a 50-mm (2-in.) pipe plug. Also shows insulation method and
attachment of corrosion coupon.
3.3.4Two examples of special-purpose coupon holders that provide for installation and removal of the coupon from a pressurized system are shown in Figures 5 and 6. An installation tool that can be used with conventional valves is shown in Figure 5. An installation assembly that requires a special fitting on a line or vessel is shown in Figure 6. When install-ation and removal of coupons from a pressurized system is contemplated, the system design must accommodate the tool length. Overall length depends on the distance from the access valve to the final insertion depth in the pipe or vessel.
3.3.5Coupon holders to secure a disk-type coupon flush with the pipe wall are available. Coupons flush with the pipe wall are subject to less turbulence than flat or round coupons that protrude into the flowing stream. Therefore, the flush-mounted coupons should provide information that is more represen-tative of corrosion on the pipe wall. The disk-type coupons should be held in place with either plastic or coated steel screws. In some systems, iron sulfide may bridge between the coupon and pipe wall. The resulting short circuit can increase or decrease the rate of corrosion on the coupon.
3.3.6Holders for coupons to be placed in well tubing are also available. Coupons can be attached to a tubing stop (see Figure 7),12 which may be available from some subsurface pump suppliers and wire-line service companies. Another coupon holder that can be set by wire line in a side-pocket mandrel is
available from gas lift equipment suppliers and wire-line service companies.
3.4Location in the System
3.4.1To obtain the most reliable information from
corrosion coupons, as well as from any other type of corrosion monitor, the coupons should be located where corrosion is occurring or is most likely to occur. Corrosion and design engineers should collaborate to ensure that sufficient access fittings for corrosion monitoring are included in the design of new facilities. In existing operating systems, cor-rosion failure records can identify corrosive areas.
Ultrasonic and radiographic metal thickness meas-urements can be made to locate areas where corrosion has occurred. Coupons can function in either the liquid or vapor phase of a system. In new systems, experience with other similar systems can often be helpful. The following locations for coupons should be considered: (1) dead fluid areas; (2) high-velocity fluid streams and impingement points; (3) downstream from points of possible oxygen entry, such as tanks, pumps, vapor recovery units, and water makeup lines in gas sweetening systems; (4) locations where water is likely to collect in sour(6) systems, such as suction scrubbers on compressors, separators, water drain lines from dehydrators, and low spots in wet gas lines; (5) amine and glycol streams that contain sour gas; (6) vapor sections in sour glycol regenerators; and (7) areas where a liquid/vapor interface occurs.
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(6) The term sour is used in this standard to denote systems containing hydrogen sulfide (H
2S).
Corrosion coupon
Screw and nut of an insulating,
nonmetallic material.
Insulating post made of
nonmetallic material and ground
flat in area where coupon
attaches. Post is grouted in with
an epoxy cement.
50-mm (2-in.) pipe plug
(plug size and type can
be varied to fit system
connections and
pressures).
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3.4.2In lines handling wet gas, water can accumulate at changes in the line elevation as depicted in Figure 8. Corrosion may be accelerated where water has accumulated. Coupons in such systems must be located where they will be water-wet to correlate with corroding areas. Coupons located in the vapor phase could indicate only slight corrosion when water-wet areas are corroding severely.
3.4.3Corrosion on subsurface well equipment can be monitored by installing cleaned and weighed tubing subs, or pup joints (600 mm [2 ft] long) can be installed in the sucker-rod string as corrosion coupons. The tubing and rod subs should be located near the bottom, middle, and top of the well. The use of coupons in the sucker-rod string is usually unnecessary because each rod in the string acts as a coupon.
3.4.4Corrosion of wellhead fittings on high-velocity flowing wells that produce organic acids, carbon dioxide, and water may be very severe. Corrosion coupons should be located both upstream and downstream from chokes to evaluate the effects of changes in velocity, temperature, and phases.
3.4.5Coupons located in flow lines of wells may be affected by paraffin accumulation. Coupons should be located in a section of the line that is free of paraffin deposits. Coupons located in surface lines from wells may not provide accurate information on downhole corrosion rates. However, trends can usually be identified.
3.4.6Flat coupons should be oriented in the system so that one edge faces the fluid flow. Replacement coupons should have the same orientation as previous coupons. Records should indicate the exact location of the coupon in a line or vessel (i.e., top, middle, or bottom).
3.4.7Corrosion in pipelines with small quantities of water is often monitored with test nipples (see Paragraph 3.6.1). Corrosion coupons must be carefully placed to ensure that they are subjected to
the line’s corrosive conditions. Coupons should be
installed in both liquid and vapor phases.
FIGURE 4 — Round (rod-type) coupon holder using a 50-mm (2-in.) pipe plug and special insulating disk
that can accommodate eight round (rod-type) coupons.
6.4 x 102 mm (0.25
x 4.00-in.) round
corrosion coupon
6.4 x 35.0 mm (0.25
x 1.38-in.) round
corrosion coupon
Threaded bolt (steel) to
fasten disc to pipe plug
Disk made of TFE-
fluorocarbon or similar
insulating material with
eight 6.4-mm (0.25-in.)
holes drilled and tapped
for corrosion coupons.
50 mm (2-in.) pipe
plug (plug size and
type can be varied to
fit system connections
and pressures).
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FIGURE 5 —Tool for installing and removing coupons in systems under pressure. The pipe nipple screws into an existing valve on the line or vessel. Complete assembly is shown on left. After the
coupon has been positioned, the drive unit is removed and the coupon holder is locked as shown on the
right.
FIGURE 6 — Extractor tool for inserting and removing coupons in systems under pressure: (a) insertion assembly used to install coupon holder in access fitting. Insertion assembly is removed after coupons are placed in access fitting; and (b) cutaway of special access fitting used with extractor tool. Fitting is
welded to line or vessel. Shown with coupon and holder installed.
3.4.8In horizontal multiphase flow, phases can sometimes be stranded. Care must be taken to ensure the coupon is exposed to the corrosive phase(s). For example, in a wet gas system, flush disk-type coupons can be placed in annular flow sections of the pipe to ensure contact with the water phase.
3.5Exposure Time
3.5.1Exposure time must be considered when interpreting corrosion coupon data. Short-term exposure (15 to 45 days) provides quick answers but may give higher corrosion rates than long-term exposures. Aggravating conditions, such as bacterial fouling, may take time to develop on the coupon.
RP0775-99
Short exposure times may be advantageous when evaluating inhibitor effectiveness. Longer exposures
(60 to 90 days) are often required to detect and
define pitting attack. Multiple coupon holders can be used so that both the short- and long-term effects can be evaluated. Because exposure time affects test results, exposure periods should be as consistent as practical. A tolerance of ±7% allows a variation of ±2 days on a 30-day exposure. This is satisfactory for most applications.
3.5.2When coupons are used to evaluate and
monitor corrosion-inhibitor treatment, new coupons should be installed just prior to treatment. This is particularly important when there is a long period between treatments (as in inhibitor squeeze, tubing displacement, and infrequent batch treatment of gas wells).
3.6Other Monitoring Devices
3.6.1Test Nipples/Spools. These are normally
short (300- to 900-mm [1- to 3-ft]) lengths of tubular goods of the same size and metal composition as the material used in the system. If test nipples are made from the same material as adjacent piping, galvanic corrosion of the test nipple is not a problem and insulating the nipples from the pipe should not be necessary. If the compositions of test nipples and piping are different, electrical isolation should be used to prevent galvanic corrosion. Electrical isolation of test nipples in lines operating above 14 MPa (2,000 psi) and 93°C (200°F) is practical only if flanged spools are used for test nipples.
3.6.1.1Test nipples are usually exposed for
longer periods (90 days to two years) than
coupons. Shorter exposure periods can provide
some information, but accurate pitting rate or
mass-loss determinations may require exposure
of six months or more.
3.6.1.2Test nipples should be cleaned and
accurately weighed prior to and after exposure to
allow calculation of corrosion rate during the
exposure period.
3.6.1.3Mass loss may also be determined by
accurate measurement of the internal volume of the test nipple before exposure and again after exposure and cleaning. To measure pit depths, nipples can be split longitudinally after mass loss is determined.
3.6.1.4The external surface of the test nipple
should be protected from atmospheric or soil corrosion if the mass loss is to reflect only internal corrosion. The addition of heavy flanges to a corrosion nipple may prevent accurate direct mass-loss measurements. However, flanged nipples can provide useful data on pitting rates.
3.6.1.5Test nipples/spools should be cleaned,
and volume, mass, or wall thickness measure-ments accurately determined prior to and after exposure to allow calculations of corrosion rate during the exposure period.
3.6.2Electronic Devices.13-16 Electronic corrosion and inhibitor film monitoring instruments include electrical resistance measuring instruments, polar-ization instruments, galvanic probes, and electrolytic and vacuum-type hydrogen probes. All of these instruments are useful in detecting short-term upsets that may not be detected by coupons, which measure average corrosion rates. Some of the polarization and galvanic probes have removable metal elements that can be weighed before and after exposure.
3.6.3Hydrogen Probes. Corrosion coupons can be attached to the ends of pressure-type hydrogen probes to compare coupon mass loss to the amount of hydrogen collected in the hydrogen probe. The coupon is isolated electrically from the body of the hydrogen probe.17
3.6.4Additional Methods for Monitoring Corrosion. Additional monitoring methods that can be used in conjunction with coupons are listed in Paragraph 1.3.
RP0775-99
FIGURE 7 — Wire-line-operated tubing stop adapted as downhole coupon holder.
RP0775-99 FIGURE 8A. WITH LOW FLOW RATE (BELOW LIMITING VELOCITY)*
A. WATER OSCILLATES—CORROSION ACCELERATED.
B. B. CORROSION NOT ACCELERATED.
C. C. WATER IMPINGES AT C—CORROSION ACCELERATED WITH
HIGHER FLOW RATE (ABOVE LIMITING VELOCITY)*
CORROSION MOST SEVERE AT IMPINGEMENTS
*LIMITING VELOCITY—VELOCITY ABOVE WHICH EROSION DAMAGE CAN BE
EXPECTED.
FIGURE 8B. LOW FLOW RATE
CORROSION MOST SEVERE AT B AND C.
HIGH FLOW RATES
CORROSION MOST SEVERE AT A.
A. B.
FIGURE 8C. VERTICAL RISER IN GAS LINE CARRYING SMALL VOLUME OF WATER
A. IN HIGH-VELOCITY FLOW, WATER IMPINGES ON POINTS A AND B,
ACCELERATING CORROSION.
B. AT LOW VELOCITY, WATER ACCUMULATES IN UPSTREAM LEG OF LOOP,
CASCADES DOWN IN DOWNSTREAM LOOP, IMPINGING AT POINT A.
FIGURE 8 — Choice of location for coupon installation and interpretation of coupon corrosion rate measurements must take into consideration possible fluid-build-up locations and impingement points. This figure shows what can occur at changes in direction and elevation in a wet gas system. Whether the conditions described actively exist depends on many factors, particularly velocity.
RP0775-99
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Section 4: Recording Data on Corrosion Coupon Report
4.1The typical corrosion coupon report form in Appendix
A shows the type of information that should be reported in a corrosion-monitoring program. A separate form should be used for each coupon. Similar coupon report forms are available from commercial laboratories and inhibitor suppliers. Complete records of coupon testing are very important in evaluating corrosion-mitigation programs.
_______________________________________________________________________ Section 5: Interpretation of Corrosion Coupon Data
5.1Data from corrosion coupons and other monitoring instruments seldom correlate exactly with the rate of corrosion observed in the system. Factors that can contribute to the lack of correlation include coupon location and multiphase flow characteristics. Coupons installed in a single-phase system, such as a water injection line, correlate with corrosion rates on system components better than coupons in three-phase systems of oil, water, and gas. In stratified multiphase systems, attack may be confined to the part of the coupon exposed to the corrosive phase. Coupons provide valuable infor-mation for long-term exposures. Intermittent conditions such as periodic entry of oxygen into a water system or water into a gas system usually cannot be characterized by standard corrosion coupons with any degree of accuracy. Banded coupons can sometimes provide qualitative evidence of intermittent oxygen entry. Such intermittent conditions can be detected by recording polarization or galvanic instruments (liquid phase) or by resistance-type instruments that are read frequently (liquid or gas phase). Coupon data reflect only the average rate of corrosion during the test period.17 Major changes such as the initiation of an effective mitigation program can be evaluated with corrosion coupons. Coupons can be useful in providing back-up for other types of corrosion monitors.13-17 Coupon data should be correlated also with the corrosion failure frequency in the system being studied.
5.2Continuous monitoring is essential so that changes in the corrosion rate in a system can be detected as soon as possible after they occur. This permits early miti-gation, which can prevent dangerous and expensive equipment failures.
5.3Qualitative guidelines for interpretation of measured corrosion and pitting rates are given in Table 2. The average corrosion and pitting rates shown in Table 2 are intended for use only as guides. The table was compiled from information on carbon steel systems. Common sense must be exercised in the evaluation of corrosion rates as shown by corrosion coupons. Coupons installed in dynamic systems may indicate a higher rate of corrosion than is actually occurring on the interior wall of the system piping. Conventional coupons protrude into the flow stream and are thus subject to more turbulence than the pipe wall. Also, coupons are initially clean and free of protective films that may be providing considerable protection to the pipe wall. The rate of corrosion of a coupon may be much greater during the first days than after an exposure of one month. After the coupon has been exposed to the environment, protective films such as oil, carbonates, iron oxides, and sulfides may begin to form on the coupon and slow the rate of corrosion. In other systems, corrosion rates may increase with longer exposure time. Pitting sometimes begins only after an “incubation period.” Underdeposit corrosion usually becomes severe only after the coupon is exposed long enough for deposits to form. A coupon made of a corrosion-resistant metal may be exposed adjacent to the coupon under test to assess the effects of mechanical erosion.
5.3.1Use of guidelines in Table 2 must be tempered
by economic considerations and safety requirements.
For example, a short-lived project can normally tolerate a higher corrosion rate than a long-term, high-investment project.
5.3.2The average corrosion rate calculation
(Paragraph 2.4.1) assumes a uniform loss of metal, which is usually not the case in production operations. These data must be tempered by the maximum pitting rate (Paragraph 2.5) to determine the severity of the corrosion from an operation standpoint. A pitting rate of 0.13 mm/y (5.0 mpy) on
a thin-walled heat exchanger tube is serious. The
same rate of pitting on a 76-mm (3.0-in.) thick casting is normally inconsequential. Pitting rates should be evaluated in light of the considerations outlined in Paragraph 2.5.
RP0775-99 Table 2 — Qualitative Categorization of Carbon Steel Corrosion Rates for Oil Production Systems
Average Corrosion Rate Maximum Pitting Rate (See Paragraph 2.5)
mm/y(A)mpy(B)mm/y mpy
Low<0.025<1.0<0.13<5.0 Moderate0.025-0.12 1.0-4.90.13-0.20 5.0-7.9
High0.13-0.25 5.0-100.21-0.388.0-15 Severe>0.25>10>0.38>15
(A) mm/y = millimeters per year
(B) mpy = mils per year
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References
1.I. Kayafas, Corrosion 36, 8 and 10 (1980): p. 443, 585.
2.NACE Standard TM0169 (latest revision), “Labor-atory Corrosion Testing of Metals” (Houston, TX: NACE).
3.H.G. Byars, B.R. Gallop, Materials Performance 14, 11 (1975): p.9.
4.ASTM G 1 (latest revision), “Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens” (West Conshohocken, PA: ASTM).
5.ASTM G 4 (latest revision), “Standard Guide for Conducting Corrosion Coupon Tests in Field Applications” (West Conshohocken, PA: ASTM).
6.Journal of Petroleum Technology, “Part 1 - The International System of Units” 37 (1982): p. 2019-2056.
7.Journal of Petroleum Technology, “Application of the SI Metric System - Part 2 - The Basic Units” 37 (1985): p. 1801.
8.ASTM E 380 (latest revision), “Standard Practice for Use of the International System of Units (SI)” (West Conshohocken, PA: ASTM).
9.ASTM G 46 (latest revision), “Standard Guide for Examination and Evaluation of Pitting Corrosion” (West Conshohocken, PA: ASTM).10.API RP 13B-1 (latest revision), “Standard Procedure for Field Testing Water-Based Drilling Fluids”(Washington, DC: API).
11. F.L. LaQue, T.P. May, and H.H. Uhlig, Corrosion in Action (New York, NY: International Nickel Co. Inc., 1955), p. 27.
12.Corrosion of Oil and Gas Well Equipment, 2nd ed. (Dallas, TX: API, 1990).
13.NACE Publication 3D170 (latest revision), “Modern Electrical Methods for Determining Corrosion Rates”(Houston, TX: NACE).
14.T.W. McSpadden, “Corrosion Monitoring Tech-niques” AGA Operating Section Proceedings, paper no. 78-T-36 (Arlington, VA: American Gas Association (AGA), 1978).
15.S.L. Cole, Materials Performance 18, 1 (1979): p.16.
16. D.R. Fincher, A.C. Nestle, and J.J. Marr, Materials Performance 15, 1 (1976): p. 34
17.NACE Publication 1C184 (latest revision),“Monitoring Corrosion in Oil and Gas Production Operations with Hydrogen Probes” (Houston, TX: NACE).
RP0775-99
Appendix A — Typical Corrosion Coupon Report
Lease or facility Well number ____________________________________ Well or facility type ____________________________________________________________________________________ Flowrates-Oil, m3/d (BOPD)_____________________________Water, m3/d (BWPD) _______________________________ Gas, m3/d (MMCFPD)__________________________________________________________________________________ Temperature_____________________°C (°F) Pressure ____________________________________________MPa (psig) Fluid analysis (attach if lengthy)__________________________________________________________________________ ____________________________________________________________________________________________________ Gas analysis (attach if lengthy)___________________________________________________________________________ ____________________________________________________________________________________________________ Coupon location in system ______________________________________________________________________________ Sketch of system with coupon position shown:
Coupon
number_________________________________Material______________________________________________________ Surface finish_____________________________Exposed area_________________________________________________ Dimensions __________________________________________________________________________________________ Installation date____________________________Installation mass _____________________________________________ Removal date______________________________Removal mass ______________________________________________ Days in system_____________________________Mass after cleaning___________________________________________ Mass loss __________________________________________________ Average corrosion rate: mm/y (mpy)
Deepest measured pit___________________mm (mils) Maximum pitting rate___________________________mm/y (mpy) Description of deposit before cleaning _____________________________________________________________________ ____________________________________________________________________________________________________ Analysis of deposit ____________________________________________________________________________________ ____________________________________________________________________________________________________ Description of coupon after cleaning (e.g., etch, pitting, erosion, etc.)_____________________________________________ ____________________________________________________________________________________________________ ____________________________________________________________________________________________________
Chemical treatment during exposure ______________________________________________________________________ ____________________________________________________________________________________________________ Other remarks________________________________________________________________________________________ ____________________________________________________________________________________________________ ____________________________________________________________________________________________________
ISBN 1-57590-086-6