Heidersbach R. Metallurgy and Corrosion Control in Oil and Gas Production

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INSPECTION, MONITORING, AND TESTING 189

Figure 7.5 Ultrasonic pulse - echo transducer with sample.

Contact

Ultrasonic

Transducer

Couplant

ABC

Crack

Pit

Figure 7.6 Pulse - echo display of the sample shown in

Figure 7.5 .

Distance →

Back

surface

echo

Crack

echo

Pit

echo

ABC

Amplitude →

Figure 7.4 Magnetic particle crack indications on the exter-

ior of a petroleum pipeline.

Beneﬁ ts of MT :

•

Relatively simple and rapid method of inspection

•

May detect ﬁ ne cracks missed by eye and dye

penetrant

Limitations of MT :

4,14,15

•

Extensive training necessary

•

Only ferromagnetic materials inspected

•

Requires smooth, clean surface

•

Paint or coatings may reduce sensitivity

•

May need to demagnetize surface after inspection

Ultrasonic Inspection ( UT )

UT uses high - frequency sound waves to measure the

distance from a source transducer to a reﬂ ection source

such as a defect or metal surface, for example, the oppo-

site side of the metal being inspected. Any change in

density of the material through which the sound wave

is traveling will produce an echo which can be detected

by ultrasonic detectors. This technique is usually used

as a portable technique where the transducer (Figure

7.5 ) is placed on the metal surface to be inspected. The

pulse (sending sound waves) - echo (receiving sound

waves) technique is the most common UT technique.

High - frequency sound waves are introduced into a

material (pulse), and reﬂ ected sound (echo) measure-

ments indicate the distance from the material surface

that the reﬂ ections (echoes) are coming from. Figures

7.5 and 7.6 show a typical setup where a transducer

(sound source and receiver) is placed on the surface,

and echoes from defects within the material and from

the far side of the material produce three different

return signals — the original pulse at the surface A, an

echo from beyond the center of the sample B, and an

echo from the far surface. The pulse - echo technique is

used for determining remaining wall thicknesses due to

corrosion and for weld ﬂ aw detection during construc-

tion and repairs.

It is common to monitor corrosion by inspecting in

the same location at locations marked on the outside of

pressure vessels and topside piping. Ultrasonics are also

used for one - time inspections, as shown in Figure 7.7 .

One limitation of conventional pulse - echo UTs is

that they only indicate the condition of the structure at

locations near the ultrasonic transducer. Other UT

techniques have been developed to measure larger

areas, although they are less commonly used.

Beneﬁ ts of UT :

•

Only requires direct access to one side of the test

piece

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190 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

Oilﬁ eld radiography uses X - ray generators, which

require high - voltage electricity, or radioisotopic gamma

rays. Isotopic radiation sources are limited in the radia-

tion ﬂ ux they can produce, and they often require longer

exposure times than X - rays. A number of radioactive

isotopes are available, but Iridium 192 is the most com-

monly used gamma source for oilﬁ eld use.

At one time, image capturing was with ﬁ lm, but

recent advances in electronic radiation detection are

capturing much of the market. These electronic methods

use similar equipment, for example, image plates,

but they can be processed much quicker, present no

chemical disposal problems, and are more amenable to

automated image transfer and analysis. These advances

have led to signiﬁ cant cost and time reductions.

Radiography detects differences in mass between the

source and the imaging device. Heavier or thicker mate-

rials require longer exposure times, and lighter materi-

als may not be detected. This can be an advantage, as

radiography of coated pipelines does not require coating

removal before examination. This is shown in Figure

7.9 , which shows the effects of erosion corrosion on the

inside of a coated pipe.

Radiography allows inspection and imaging of mate-

rials lighter than metals. This is shown in Figure 7.10 ,

where a region of debonding has been located in a

nonmetallic liner using radiography. A nearby ﬂ ange

showing the lining is shown in Figure 7.11 . Despite this

capability, the great majority of oilﬁ eld uses for radiog-

raphy remain in weld quality and metal loss imaging.

Radiation safety is a major concern when using

radiography, and dosage monitoring of all nearby

personnel, exclusion of non - necessary personnel from

Figure 7.7 Ultrasonic inspection every meter at the 12 o ’ clock

position on an exposed pipeline. Note the dark areas on the

pipeline where dirt and debris have been removed so that good

sensor contact can be maintained with the pipeline surface.

•

Accurate thickness and ﬂ aw depth measurement

•

Can penetrate thick materials

•

Analytic techniques, based on ANSI/ASME B31G,

API 653, API 510 and 510 and similar codes, can

be used for determining maximum allowable oper-

ating pressures and estimated remaining service

life.

4,7,13,16 – 19

Limitations of UT :

•

Training is relatively extensive and may require

several years of experience to produce skilled

inspectors

•

Limited use on very thin material

Radiography ( RT )

The use of X - rays and gamma rays has been applied to

industrial inspection for many years. The techniques are

very similar to those used for medical radiography, and

many advances in medical radiography have been

adopted for industrial applications.

Common oilﬁ eld uses for radiography include weld

quality inspection, weight loss corrosion inspections,

and the measurement of the extent of scale, hydrate,

and parafﬁ n buildup inside pipelines. A typical radio-

graphic exposure using ﬁ lm as a radiation detector is

shown in Figure 7.8 . The radiation is absorbed by any

material between the source and the detector. Figure

7.8 shows that thin cracks are normally missed by radi-

ography, but volume defects, for example, pitting cor-

rosion and internal porosity, are readily detected.

Figure 7.8 Schematic of ﬁ lm radiography of a metal with a

corrosion pit, an internal crack, and internal porosity defects.

Thin crack

Radiation source

Porosity

Darkened area (when developed)

Film

Surface pitting

Metal plate

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INSPECTION, MONITORING, AND TESTING 191

•

Access to both sides of the structure is necessary

•

Radiation safety precautions necessary

•

Free access necessary for radiation source

•

Orientation of crack - like defects means they may

be missed

•

Expensive

Because radiography cannot determine the depth of

internal defects and will miss tight cracks like those

shown in Figure 7.8 , it is common to combine radiogra-

phy with UT. The two techniques are considered com-

plementary in locating and identifying internal defects.

Eddy Current

Eddy current inspection can be used on any electrically

conductive material. Alternating electromagnetic ﬁ elds

induce circulating eddy currents (electron ﬂ ow) in the

material being inspected. Defects, for example, cracks,

bulges, corrosion pits, alter the ﬂ ow of these currents

and reduce the secondary magnetic ﬁ eld of the part

under inspection. Changes in conductivity and magnetic

permeability are analyzed and correlated with ﬂ aws.

The basic equipment consists of an alternating elec-

trical current source, a connected coil (probe) that can

be passed near the part being inspected, and a voltmeter

to measure the voltage change across the coil. The

examination process involves moving the probe across

the part being inspected and noting where the current

changes. Figure 7.12 shows inspection of heat exchanger

tubing. In this type of inspection it is common to draw

the probe through the tubing and note locations where

the exposure area, and appropriate radiation shielding

are all necessary.

Beneﬁ ts of Radiographic Inspection:

1,4,7,20

•

Rapid using electronic cameras instead of ﬁ lm

•

Image as permanent record

•

Coatings and thin surface deposits are transparent

which allows minimal surface preparation

•

Can be used on most materials

•

Shows fabrication errors (e.g., misalignments),

weld defects, and weight loss corrosion

Limitations of Radiographic Inspection:

1,4,7,20

•

Only local areas can be inspected

•

Only 2D image — no information on depth of defect

Figure 7.10 Radiograph showing damage to nonmetallic

pipe liner.

Figure 7.11 Flange near damage shown in Figure 7.10 .

Figure 7.9 Radiograph showing erosion corrosion at piping

bend. Photo courtesy of NACE Basic Course.

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192 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

Figure 7.13 shows one of these XRF analyzers in

operation. All the operator needs to do is clean the

surface so that the bare metal is exposed and turn on the

detector. The machine will analyze the sample in a matter

of seconds and compare it with a series of preloaded

alloy possibilities before providing the nearest match.

Hand - held PMI detectors have become the industry

standard for PMI of corrosion - resistant alloys (CRAs).

The portable X - ray spectrometers used for this purpose

cannot detect carbon and other light elements, and

hardness testing is the traditional way of sorting carbon

steel samples.

Beneﬁ t of PMI :

Fast and accurate alloy

identiﬁ cation

Limitations of PMI :

•

Radioactive, requires secure storage and dosage

monitoring

•

Cannot analyze carbon steels and other light

elements

•

Requires direct access to cleaned surface for

analysis

•

Initial equipment cost is relatively high compared

to some other techniques

Thermography

Thermography uses infrared cameras to detect temper-

ature differences in equipment. It is often used as a

remote inspection technique to determine ﬂ uid levels in

storage tanks, ﬂ uid leaks on insulated piping, losses in

wall thickness due to erosion corrosion, and a variety of

indications appear. Further inspection, for example,

with ultrasonics, can identify the extent of the irregular-

ity detected by eddy current. Heat changer inspections

can analyze many tubes very quickly. It is common to

block off any tubes with eddy current irregularities until

the total number of blocked tubes affects equipment

performance.

Beneﬁ ts of Eddy Current Inspection:

•

Detects both surface and slight subsurface defects

•

Probes do not have to contact the part

•

Works through paint and some coatings

Limitations of Eddy Current Inspection:

•

Relatively extensive training is required

•

Limited to conductive materials

•

Limited depth of penetration

Positive Material Identiﬁ cation ( PMI )

This term is applied to identiﬁ cation and conﬁ rmation

of alloy materials using hand - portable X - ray ﬂ uores-

cence (XRF) spectrometers.

A radiation probe, usually

using a radioactive isotope, is placed on the sample in

question and X - rays from the sample being tested are

analyzed using equipment - mounted software. Most of

these instruments can be programmed for dozens of

alloys and the typical readout tells the operator the

alloy with the closest match to the detected X - rays.

Figure 7.12 Eddy current inspection of heat exchanger

tubes.

Figure 7.13 Hand - held Thermo Scientiﬁ c Niton X - ray ﬂ uo-

rescent spectrometer being used for positive materials identi-

ﬁ cation. Photo courtesy of Thermo Fisher Scientiﬁ c.

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INSPECTION, MONITORING, AND TESTING 193

replaced at the appropriate time and a subsequent

ﬁ lling of the tank produced the slumping shown in this

picture.

Upstream oil and gas operations have many routine

inspections, but in far too many cases, the inspection

process becomes routine, and organizations do not

realize the implications of reports available somewhere

in their organization. Preventable leaks and damaged

equipment are sometimes the unfortunate results.

Many organizations would beneﬁ t from recognizing

the Pareto principle that most problems are associated

with a small fraction of their equipment.

2,3

Risk - based

inspection procedures are attempts to apply this think-

ing.

Having more inspections is often counterproduc-

tive. Conducting the right inspections, in the most

important high - risk locations, is preferable to having so

many inspections that the organization spends too much

time conducting inspections and too little time thinking

about what these inspections mean in terms of safety

and reliability.

Many organizations have maintenance and inspec-

tion budgets related to production volumes. As pro-

duction ﬁ elds age and production volumes decrease,

equipment ages, and many production ﬂ uids become

more corrosive. The need for increased inspection and

maintenance suffers from decreasing budgets at times

of increasing needs for inspection and maintenance.

MONITORING

Inspection is used to determine the condition of equip-

ment at the time of inspection while monitoring allows

operators to determine if conditions and corrosion rates

are changing. The two techniques are complementary,

and both are necessary.

Corrosion monitoring is used to determine changes

in the corrosivity of environments and to determine the

effectiveness of corrosion control techniques such as

chemical inhibitor injection.

Most oil ﬁ elds become

more corrosive as ﬁ elds age, production rates decrease,

and water cuts increase. Souring of formations, often

caused by inadequate injection water treatment, can

also cause increased corrosivity. In low - temperature,

low - pressure situations where corrosion inhibitors are

used to minimize and control corrosion rates of carbon

steel, the proper application of corrosion monitoring

becomes the principal means of determining and main-

taining corrosion control.

Monitoring Probes

Most monitoring techniques require the insertion of

metal samples of some type into corrosive production

other purposes.

The technique cannot identify the

reason for the detected temperature differences. It is

used as a quick means of determining locations where

closer inspection using other means are appropriate.

Beneﬁ t of Thermography:

Identiﬁ cation of hot spots,

for example, due to scale buildup in furnaces or leaks

in thermal insulation

Limitation of Thermography:

Cannot determine cor-

rosion or wall thinning

Additional Remarks about Inspection

There are a number of other inspection techniques used

in oilﬁ eld applications, including magnetic ﬂ ux leakage

(MFL) for internal inspection of pipelines and alternat-

ing current ﬁ eld measurement (ACFM) for external

crack detection.

Inspectors need guidance on how to collect and

analyze, or protect for shipment for laboratory analysis,

biological samples, and surface deposits.

One of the biggest problems with inspection is that

it can become routine, and organizations may not pay

attention to the results of inspection. This is shown in

Figure 7.14 , which shows an acid storage tank built from

carbon steel that experienced gradual wall thinning due

to corrosion. The use of carbon steel for the storage of

concentrated sulfuric acid is an accepted industry prac-

tice.

7,22,23

This tank was inspected on a regular basis to

determine the extent of the expected gradual wall thin-

ning, and the original design called for replacement

once the thinning reached a certain prescribed extent.

Unfortunately, the inspection reports, which proved to

be accurate, were ﬁ led and not brought to the attention

of the appropriate decision makers. The tank was not

Figure 7.14 Slumping storage tank due to wall thinning.

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194 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

ment (Figure 7.16 ). For these reasons, most probes will

have slightly higher corrosion susceptibilities than the

actual structures in which they are placed. This pro-

duces slightly increased corrosion rates, which are con-

servative and are to be desired. The statistical nature of

pitting and other forms of localized corrosion also mean

that monitoring with small corrosion probes cannot rep-

licate the corrosion rates of larger metallic structures. It

is also difﬁ cult, and often impossible, to place probes in

the most corrosion - susceptible locations in a compli-

cated piping system.

While the true corrosion rates of large - scale equip-

ment cannot be determined from small corrosion probes,

“ awareness of changes in the corrosion rate is often the

major requirement of monitoring with the absolute

value of the corrosion rate being less important. ”

Mass - Loss Coupons and Probes

The most common equipment used for corrosion moni-

toring is the insertion of mass - loss coupons into the

environment of interest. Fittings such as those shown in

Figure 7.16 are often used for this purpose. It is impor-

tant that the coupons be inserted in the appropriate

location, usually top or bottom depending on whether

gas - phase or water - phase corrosion is being monitored.

Unfortunately, it is all too common for the ﬁ ttings and

probes to be placed in the most convenient access loca-

tion, and this means that many coupons are not exposed

to the corrosive conditions they are intended to monitor.

Figure 7.17 shows a typical weight loss coupon after

exposure in an oilﬁ eld environment for 3 months. The

arrows indicate locations of pitting.

NACE and other standards prescribe methods of

analyzing coupons to determine the average (weight

loss) corrosion rate and the pitting rate, based on the

depth of the deepest pit on the coupon.

It should be

noted that these methods calculate corrosion rates aver-

aged over the exposure times and do not take into

account the possibilities that the observed corrosion

ﬂ uids. Two typical arrangements are shown in Figure

7.15 . The corrosion coupon shown on the left is exposed

to produced water at the bottom of the pipe and to

oil which is ﬂ owing above the denser water. The

ﬂ ush - mounted probe on the right is only exposed to

the produced water on the bottom of the pipe. It is

obvious that the two different probes will be exposed

to different corrosion environments and return differ-

ent information.

It is important to monitor corrosion in the appropri-

ate location. Common locations for internal corrosion

are near the bottom or the top, depending on whether

corrosion is expected from the water or the gas phase.

Oil is generally noncorrosive.

A major limitation of monitoring systems is the

limited size and shape of the probes used to monitor

corrosion. Probes are manufactured from wire, sheet,

or plate having chemistries close to, if not the same as,

plate and tubular products used in oilﬁ eld applications.

The crystal orientation and relative grain boundary

areas of the exposed probe samples are different than

the ﬂ at, as - rolled or as - drawn surfaces of most equip-

Figure 7.15 Intrusive and ﬂ ush - mounted corrosion probes

inserted into a three - phase production system.

Gas

Produced water

In normal 3-phase flow the gas, oil and water are not fully

separated as depicted.

Oil

Figure 7.16 Rolling direction and resulting grain structures.

Rolling

Direction

Longitudinal

Long Transverse

Short Transverse

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INSPECTION, MONITORING, AND TESTING 195

try, thermal and mechanical processing history, nature

of inclusions and other imperfections, and so on, are

likely in these coupons. These differences seldom affect

the results of weight loss and pitting determinations, but

they can produce unintended results in some environ-

ments. Figure 7.19 shows a typical carbon steel coupon

purchased from a major coupon supplier and exposed

in an H

S - containing environment. The arrows show

locations of hydrogen - induced cracking. The carbon

steel in this coupon was harder (HRC27) than the

OCTGs used in the equipment where the coupon was

exposed. While the coupon had cracking, none is likely

to occur on the piping system being monitored.

Coupon exposure time must be considered. Short -

term exposures (15 – 45 days) are likely to indicate higher

corrosion rates than longer - term exposures. It takes

time for bioﬁ lms, scale deposits, and pitting to develop.

Longer exposures (60 – 90 days) are sometimes neces-

sary to detect and deﬁ ne pitting attack.

Pitting is nor-

mally analyzed using optical microscopes at relatively

low magniﬁ cations. Figure 7.20 shows corrosion coupons

from an offshore gas ﬁ eld analyzed using a scanning

electron microscope. These instruments are able to

observe surfaces at much higher magniﬁ cations and

detect pitting that would be missed at lower magniﬁ ca-

tions.

This allows for faster corrections to corrosion

inhibitor treatments. Many oilﬁ eld service companies

have access to these microscopes, but the use of scan-

ning electron microscopes for coupon analysis remains

unusual.

Beneﬁ ts of Mass - Loss Coupons:

4,7

•

Can be used in any corrosive environment

•

Relatively simple procedure, easily understood,

and widely accepted

may have occurred due to process upsets over a short

interval of time during the exposure. This is a major

limitation of the way most coupon exposure testing is

conducted. Pitting initiation takes time, and there is no

way of determining from mass - loss exposure coupons

when, during the exposure interval, pitting, or any other

form of corrosion, has occurred. The mass - loss corro-

sion rate also assumes that corrosion is general corro-

sion, which is seldom true for oilﬁ eld environments.

One means of determining if corrosivity has changed

during the exposure interval is to use planned interval

corrosion testing, a procedure that has been available

since the 1940s. The principles of this method are shown

in Figure 7.18 . The method requires exposing numerous

samples for different periods of time and comparing the

corrosion rates for the various exposures.

This method, which has been available since the

1940s,

has been generally supplanted by online electri-

cal corrosion monitoring techniques that can determine

changes in corrosion rates in much shorter times. These

techniques are discussed later in this chapter in the sec-

tions on monitoring and testing.

Corrosion coupons are normally supplied by compa-

nies that specialize in the preparation of these samples

from standard alloys in accordance with Universal

Numbering System (UNS) and similar alloy chemical -

content standards. These alloys are similar to API - grade

oil country tubular good (OCTG) alloys, but they are

not the same. Differences in minor constituent chemis-

Figure 7.18 Planned interval testing.

Test Specimens

0 1 Time

Occurences During Corrosion Testing

Liquid Corrosiveness

Metal Corrodibility

Unchanged

Decreased

Increased

= B

B < A

< B

= B

< B

B < A

Unchanged

Decreased

Increased

Criteria

t t + 1

t+1

Figure 7.19 Hydrogen - induced cracking on a carbon steel

mass - loss coupon.

Figure 7.17 A typical weight loss coupon after exposure to

an oilﬁ eld environment for 3 months. Arrows indicate the

three areas with pitting.

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196 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

results of microbial or other ﬁ lms that produce

underdeposit corrosion

•

Labor - intensive technique

Mass - loss coupons are the most common means of mon-

itoring the effectiveness of corrosion inhibitors for cor-

rosion control. Unfortunately, many operators have the

same contractor responsible for inhibitor application

and for monitoring the effectiveness of the inhibitors.

This conﬂ ict of interest can lead to problems. Another

problem with mass - loss coupons is that it is often impos-

sible to place them in the most corrosive locations.

Organizations that rely on this data, instead of on

inspections of the equipment involved, can experience

unanticipated equipment failures. Coupons, like all

•

Works for general attack and localized corrosion

mechanisms

•

Mass - loss coupons are relatively inexpensive

Limitations of Mass - Loss Coupons:

4,7

•

Coupons must be inserted into the ﬂ uid, exposing

personnel to potential hazards

•

Practical limitations usually mean that data is only

available 1 – 6 times per year

•

Cannot be automated

•

Only determines average corrosion rate, cannot

determine effects of upsets or unusual occurrences

•

Short exposure times overestimate general corro-

sion rates and may miss the onset of pitting or the

Figure 7.20 Scanning electron micrographs showing early indications of pitting on corrosion

coupons from an offshore gas ﬁ eld.

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INSPECTION, MONITORING, AND TESTING 197

niques. Depending on the corrosivity of the environ-

ment and the probe design, it is possible to note changes

in corrosion rates.

The resistivity of metals changes with temperature.

Modern ER probe systems have temperature com-

pensation built into the probes, so this is no longer

a problem. Electrical probes can be shorted by

sulﬁ de deposits, and this is a major limitation to ER

probe use.

Response times for ER probes depend on the cor-

rosivity of the environment and the metal cross section

of the probes. While thinner probes could be manufac-

tured, their service life would be too short, making them

impractical. At present, response times range from 0.5

to 1 day at very corrosive environments to 5 to 10 days

at the lower end of typical corrosion rates.

Beneﬁ ts of ER Probes:

4,7,28

•

Continuous online monitoring possible

•

Can be used in almost any environment

•

Useful in monitoring inhibitor persistence

•

Sensitive to both corrosion and erosion

Limitations of ER Probes:

4,7

•

Results are indicative of general corrosion or

erosion, technique does not measure localized cor-

rosion. Specialized probes can be designed to sense

crevice corrosion.

•

Probes require insertion into the corrosive ﬂ uid.

•

Response time is slower (hours to days) than for

other electrochemical monitoring techniques.

•

Iron sulﬁ de deposits can produce misleading

results.

•

Temperature compensation techniques are not

sensitive to rapid temperature changes.

Electrochemical Corrosion Rate

Monitoring Techniques

Electrochemical corrosion monitoring techniques

include:

4,7,24

other monitoring techniques, can only indicate whether

the corrosion rates are changing. They cannot identify

what the corrosion rates are on the most corroded

equipment in a system, often in deadlegs, the bottom of

upward inclines like shown in Figure 7.1 , or other inac-

cessible locations.

Electrical Resistance ( ER ) Probes

ER probes allow continuous online monitoring of cor-

rosion and are the second most common monitoring

technique for oilﬁ eld corrosion. Figure 7.21 shows

typical commercially available ER probes. The probes

are based on the principle that as corrosion or erosion

of the probe occurs, the reduced metal has increased

resistance to electrical current. Monitoring the changes

in resistance provides an indication of the corrosion

inside process equipment. Figure 7.22 shows a number

of different geometries, including several ﬂ ush - mounted

probes that do not extend into the ﬂ uid and measure

corrosion at the vessel wall level.

The output from ER probes can be transmitted to

any desired location.

These probes will work in any environment, and that

is a major advantage over other online monitoring tech-

Figure 7.21 Typical ER probes.

Figure 7.22 Voltage versus potential plot at potentials near

the equilibrium (corrosion) potential.

Current (mA)

E (mV)

10 20–20 –10

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198 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

where:

= polarization resistance, Ω (ohms)

corr

= corrosion current, amps

β = the Stern – Geary constant

The Stern – Geary constant can be calculated from theo-

retical considerations or directly measured in separate

experiments.

4,29 – 33

As a practical matter, most instru-

ment suppliers sell their instruments calibrated based

on the “ average ” Stern – Geary constant for iron and

carbon steel and on the assumption that corrosion of

iron produces Fe

+ 2

ions (instead of Fe

+ 3

ions). These

assumptions are justiﬁ ed for monitoring purposes,

because the purpose of electrochemical monitoring is to

determine if the corrosion rate is changing or is remain-

ing steady. The absolute corrosion rate is not deter-

mined, but that is not the purpose of monitoring.

LPR instruments can determine changes in corrosion

rates within minutes, sometimes even seconds. This

real - time indication that corrosion rates are changing is

the main advantage of this technique over the simpler

and more widely used ER technique, which may take

hours or days to respond to changes in corrosion

conditions.

Like all electrochemical monitoring techniques, the

electrodes must be kept free of fouling from oily depos-

its. This is a major limitation and is the reason why this

technique is not more widely used in production moni-

toring before separation processes remove hydrocar-

bons from water.

Tafel Extrapolation This technique uses the same

instrumentation as used in LPR monitoring, and most

instruments are sold with the option of operating in

either the LPR or the Tafel extrapolation mode. At

potentials greater than a few millivolts from the equi-

librium (corrosion) potential, potential - current plots

frequently become linear on a log - linear plot when the

potential is plotted on a linear basis and the current on

a logarithmic scale. This is shown in Figure 7.23 .

Prior to the application of applied current the volt-

meter reads the corrosion potential relative to a refer-

ence electrode. As applied current is increased, the

applied current versus potential curve shows no change

in potential when most of the reduction current on the

working electrode is due to the corrosion reaction.

Eventually, the effects of the applied cathodic current

become apparent and the curve slopes downward. Once

most of the current is due to the applied current, the

slope becomes linear and the original current becomes

neglible. The log - linear portion of a polarization curve

is called the “ Tafel region, ” in recognition of the

•

Linear polarization resistance (LPR)

•

Tafel extrapolation

•

Galvanic monitoring

•

Electrochemical noise

•

AC impedance spectroscopy

The ﬁ rst three techniques are appropriate for use in

oilﬁ eld monitoring applications. The latter two, while

they have many laboratory and research - oriented advo-

cates, cannot at the present time produce better results

than LPR and Tafel extrapolation. They also require

much more expensive, and delicate, instrumentation,

and will not be discussed, even though they do appear

in the corrosion literature and standards.

Most of these techniques are based on Faraday ’ s law,

which shows a direct relationship between electric

current and the mass of metal lost or deposited in an

electrochemical cell. The determination of corrosion

rates also depends on knowledge of the valency (oxida-

tion state) of the corrosion reactions.

Most instruments

are factory calibrated based on the assumption that the

corroding metal is iron or carbon steel and corrosion

produces Fe

+ 2

(instead of Fe

+ 3

) ions. This is a conserva-

tive approach and is appropriate for corrosion monitor-

ing, where changes in corrosion rates are more important

than the determination of the true corrosion rates.

LPR Linear polarization probes are sold with elec-

trodes made from the material being monitored; in most

cases this is carbon steel. The probes are small and can

be inserted into the ﬂ uids of interest in the same manner

as ER probes. The technique is based on the observa-

tion that at potentials very near ( ± 20 mV) the corrosion

potential, the voltage versus current plot is frequently

linear. This is shown in Figure 7.22 .

The polarization resistance, R

, is the slope of the

voltage versus current line near the corrosion

potential.

(Eq. 7.1)

where:

= the polarization resistance, Ω (ohms)

Δ E = the change in potential

Δ I = the change in current

The polarization resistance is then converted to a

corrosion current using the Stern – Geary equation,

Equation 7.2 :

corr

(Eq. 7.2)

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