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Note: The source of the technical material in this volume is the Professional

Engineering Development Program (PEDP) of Engineering Services.

Warning: The material contained in this document was developed for Saudi

Aramco and is intended for the exclusive use of Saudi Aramcos

employees. Any material contained in this document which is notalready in the public domain may not be copied, reproduced, sold, given,

or disclosed to third parties, or otherwise used in whole, or in part,

without the written permission of the Vice President, Engineering

Services, Saudi Aramco.

Chapter : Materials & Corrosion Control For additional information on this subject, contact

File Reference: COE10205 R. D. Tems on 873-7653

Engineering EncyclopediaSaudi Aramco DeskTop Standards

Other Corrosion Monitoring Techniques


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Engineering Encyclopedia Materials & Corrosion Control


Saudi Aramco DeskTop Standards

Contents Pages

Borescopes/Fiberscopes.................................................................................1

Theory Of Borescopes/Fiberscopes.....................................................1

Borescopes...........................................................................................2

Fiberscopes ..........................................................................................3

Application Of Borescopes/Fiberscopes ..............................................3

Limitations Of Borescopes/Fiberscopes...............................................4

Interpretation Of Borescope/Fiberscope Data......................................5

Calipers ...........................................................................................................6

Theory Of Calipers ...............................................................................6

Application Of Calipers.........................................................................8

Limitations Of Calipers .......................................................................11

Interpretation Of Caliper Data.............................................................11

Case Study A ...........................................................................15

Case Study B ...........................................................................15

Case Study C...........................................................................18

Case Study D...........................................................................20

Hydrogen Probes ..........................................................................................21

Theory Of Hydrogen Probes ..............................................................21

Application Of Hydrogen Probes........................................................24

Limitations Of Hydrogen Probes.........................................................27

Interpretation Of Hydrogen Probe Data..............................................28

Case Study A: Sour Amine Systems......................................29

Case Study B: Sour Gas Injection ..........................................30

Case Study C: West Texas Oil Well .......................................31Case Study D: Inhibitor Testing On An Absorption

Tower In An Fcc Gas Recovery

System ..............................................................31

Case Study E: Gas Well Flowline...........................................33

Case Study F: Absorber Tower In Gas Plant .........................34

Case Study G: Slightly Sour Waterflood System....................35


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Saudi Aramco DeskTop Standards

Ultrasonics.....................................................................................................37

Theory Of Ultrasonics.........................................................................37

Application Of Ultrasonics ..................................................................41

Limitations Of Ultrasonics...................................................................41

Interpretation Of Ultrasonic Data ........................................................46

Radiography..................................................................................................47

Theory Of Radiography ......................................................................47

Application Of Radiography................................................................49

Limitations Of Radiography ................................................................50

Interpretation Of Radiographic Data...................................................51

Ac Impedance ...............................................................................................52

Theory Of Ac Impedance....................................................................52

Application Of Ac Impedance .............................................................52

Limitations Of Ac Impedance..............................................................52

Sand Probes..................................................................................................54

Theory Of Sand Probes......................................................................54

Application Of Sand Probes ...............................................................55

List Of Articles ...............................................................................................56

Glossary ........................................................................................................57


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Saudi Aramco DeskTop Standards 1

BORESCOPES/FIBERSCOPES

Theory of Borescopes/Fiberscopes

Borescopes and fiberscopes are both types of endoscopes. The term endoscope is formed

from the Greek words endos(inside) and skopein(to see). Endoscopes are optical

instruments used for visual inspection of internal surfaces in tubes, holes, or other hard-to-

reach places (Figure 1). Rigid endoscopes are called borescopes. Flexible endoscopes are

calledfiberscopes.

FIGURE 1. An endoscope can be used for the visual inspection of hard-to-reach locations.


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Borescopes

A borescope is similar to a telescope,a long tubular instrument with optical lenses. While a

telescope narrows the field of view for observation at a distance, a borescope spreads the field

of view for close-up work. A borescope also has relay lenses along its length to preserve

precise resolution. Magnification is usually 3X to 4X.

Borescopes are available as one piece units or as modular units for easier storage and

handling. Self-illumination is provided either by lamps integral to the viewhead or fiber

optics(Figure 2). Using mirrors and prisms, the viewhead can provide right angle, bottom,

circumference, forward oblique, or retrospective views.

FIGURE 2. Borescope with Lenses and Optical Fiber Light Guide


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Fiberscopes

Unlike a borescope, a fiberscope can be inserted into curved pipes and cavities. Fiber optics

transmit light inside the fiberscope.

A fiberscope holds two optical bundles with as many as 120,000 individual strands of glass

fiber. The optical bundles carry light down to the inspection area and carry the image back to

the eyepiece (Figure 3). These bundles, protected by a housing of sealed stainless-steel

flexible conduit, allow the fiberscope to bend for passage around corners or sharp elbows

while sending back a clear image.

The tip of a fiberscope is easily steerable to give up to 240scanning range and sensitive

movement control.

Application of Borescopes/Fiberscopes

Borescopes and fiberscopes have a wide range of applications.

Internal visual inspection of pipes, boilers, cylinders, motors, reactors, heat exchangers,turbines, compressors, and other equipment with narrow, inaccessible cavities orchannels

Checking process piping internals for blockage prior to start-up. For instance, earlydetection of blockages is extremely critical for piping going to release stacks that vent inemergencies.

Inspection of pressure relief and other valves for damage or blockage that can causevalve failures

Examination of internal parts of gear boxes to spot bent shafts, floating gears, brokenkeys, and teeth

FIGURE 3. Image Transfer Through a Flexible Bundle of Fibers


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Many jobs place special demands upon the endoscopic equipment. Selecting the proper

equipment to meet the inspection requirements is very important. The following lists some of

the endoscopic equipment and their capabilities.

Explosion-proof and watertight. Some equipment can handle up to 3 bars. They can beused directly in liquid-filled containers and piping systems without the risk of causing anexplosion, short-circuit, or excessive handling.

Ultraviolet illumination. For surfaces treated with fluorescentmaterial, equipment withultraviolet (UV) illumination sources and quartz glass conductors provides greatersensitivity for inspection of cracks and porosity than with white light.

Cleaning/retrieving. To clean inspected areas, some models have additional channelsfor the flow of air or liquid. Other models have pincers for the retrieval of lost objects.

Optical measuring. For accurate length measurements through the viewhead, equipmentwith optical measuring gratings are available.

Adjustable viewing angle. Some models have a movable prism located at the tip of theoptical path so that the viewing angle can be varied during inspection.

Locking position. Fiberscopes can normally be maneuvered into any position by meansof a handle and then locked in place.

Camera/video. For permanent recordings, models are available with cameras or videorecorders. The video recordings reduce eye fatigue and permit group viewing duringand after inspection.

Limitations of Borescopes/Fiberscopes

A borescope offers the best choice for high resolution and rapid examination. However, it is

limited to straight-line viewing. Because it is a rigid instrument, the borescope cannot be used

in curved sections of piping and complex-shaped equipment.

Although a fiberscope can access hard-to-reach locations, it has less resolution than a

borescope.

Before a borescope or fiberscope can be used, the equipment or piping to be inspected must

be out of service.

Both borescopes and fiberscopes are sensitive to external factors. The following precautions

should be taken to prevent tool damage:

Use a soft cloth to clean lenses and the viewhead.

Protect the tool from shocks by storing it in a safe place and handling it with care whenin use.


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Never bend a fiber optics cable too sharply.

Never twist a fiber optics cable more than 360.

Never dip the tool in a liquid for which it was not designed.

Never operate the tool at temperatures beyond its design limits.

Avoid excessive heat build-up when using the built-in lamps.

Interpretation of Borescope/Fiberscope Data

The interpretation of defects, color changes, or other data requires knowledge of the materials

under examination. The choice of objective and viewing direction, evaluation of small fields

of view, and the operation of photographic and video equipment require technicalcompetence. The tool operator must be allowed to participate in a goal-oriented training

course that includes both theory and practical application of the endoscope prior to

independent endoscopic examinations.


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CALIPERS

Theory of Calipers

Downhole calipershave been in general use for many years. Mechanical calipers use spring-

loaded feelersto measure the internal diameter of tubing or casing. Calipers directly measure

general corrosion, pitting attack, or wear. Although downhole inspection with calipers is

expensive, the cost is justifiable when compared to the high cost of tubing and casing failures.

A typical caliper consists of peripheral feelers (72 maximum) that press against the inner

surface of tubing or casing. The small tips of the feelers follow the contour of internal pits or

surface deviations. The number of feelers on the the caliper determines the percentage of the

wall surface inspected. This action is illustrated in Figure 4.

As the feelers extend into a pit, a stylusrecords the diameter and/or pit depth at the locationof the feelers. Depending upon the tubing size, tubing calipers typically have between 15 and

44 feelers while casing calipers have 40 to 72 feelers.


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FIGURE 4. Caliper Feelers in Action


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Response from the feelers is sent electrically to a strip chart or mechanically scribed on a

cylinder. Calipers with an electrical response must be run on electric wire line, while the

mechanical scribing calipers can be run on a slick line (nonconductor equipment).

Calipers with a wire connection to the surface send their electrical responses to plotters for

recording. Mechanical scribing calipers record inside the tool itself. Mechanical recordings

typically require photographic enlargement or special equipment before the results can be

analyzed.

The feeler monitoring method determines how many feelers will be recorded. The three basic

methods of recording the movement of these feelers are

Single-stylus monitoring

These calipers continuously record only the onefeeler with the maximum distance from

the center line of the tool.

Minimum-maximum monitoring

The minimum-maximum monitoring method continuously records the movement of thetwo feelers that are positioned the farthest from and the nearest to the center line of thetool.

Complete monitoring

The complete monitoring method continuously and simultaneously records all thefeelers. The data recording consists of as many lines as there are feelers on the caliperand provides a complete circumferential inspection.

Application of Calipers

Typical applications of calipers include:

Detect and measure quantitatively the depth of individual pits, holes, and other corrosiondamage

Detect and measure quantitatively the corrosion activity by means of periodic survey todetermine the effectiveness of internal corrosion control programs

Produce a cross-sectional view of the inner diameter to determine the extent of damagecaused by buckling, mashes, and collapse

Schedule workovers on wells with advanced stages of corrosion


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In the last case, the duration of workovers can be reduced drastically when wells can be

worked over prior to failure. Table 1 shows how corrosion can lengthen workover time.

TABLE 1. Workover of Corroded Tubing1

Reason

Total Downtime

(days)

Estimated

Additional

Workover Days

Due to Lack of

Monitoring

Corroded tubing,

tubing/annulus communication

87 20

Corroded tubing 24 12

Parted tubing above downhole safety valve 68 30

Tubing caliper surveys are commonly run in gas, condensate, and oil wells where iron count

or wellhead coupon test data indicates severe downhole corrosion. Typical calipers include

the Dialog profile caliper, the Kinley microscopic caliper, the horizontal pipeline caliper, and

the heat exchanger caliper.

The Dialog profile caliper covers the range of 2-inch O.D. tubing to 11 3/4-inch O.D. casing.

It provides a surface electrical recording of the percentage of wall thickness remaining based

on mechanical feeler detection of internal surfaces. A typical Dialog tubing profile caliper log

is shown in Figure 5.

The Kinley microscopic caliper runs on ordinary wireline. It records downhole on a metalchart only 8 inches long by 1 inch in diameter. The movement of all feelers, typically 15, is

recorded. Models of Kinley microscopic calipers are available to survey sizes from 2-inch

tubing to 13 3/8-inch O.D. casing.

The Kinley microscopic caliper produces characteristic patterns that can be interpreted with

considerable precision. Ring and line corrosion, isolated pits, and other forms of corrosion

can be distinguished. Caliper runs up to 15,000 feet are possible.

To obtain the best survey, calipers should be pulled up a well slowly at about 60-feet per

minute. Faster speeds will usually produce an inaccurate, blurred survey and may also

damage the feelers.

Accuracy of the Kinley microscopic caliper is typically plus or minus 0.01 inch. It is capable

of withstanding temperatures as high as 500 F (260 C) with no limit on pressure.

1Houghton, C. T. and R. V. Westermark, North Sea Downhole Corrosion: Identifying the Problem;

Implementing the Solutions, Journal of Petroleum TechnologyJanuary, 1983, p. 239 - 246.


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The best frequency for inspection depends on the corrosion rate. In general, calipers are long-

term evaluation tools. Ideal frequencies for inspection surveys are typically 6 months to

1 year or more.

While most calipers are used for downhole evaluation, some calipers have been used in

horizontal pipelines and heat exchanger tubes. Horizontal pipeline calipers are generally

designed for pipe sizes ranging from 3-inch to 6-inch inner diameter with the capability to

traverse a 5-foot radius bend. Heat exchanger calipers are designed to be pulled through 3/4-,

1-, and 1 1/4-inch outer diameter tubes.

FIGURE 5. Dialog Tubing Profile Caliper Log (Typical)


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Limitations of Calipers

The contact feelers of calipers generally indicate the location of severely corroded areas but

may miss isolated pits due to the spacing of the feelers. For a single pit as small as 3 mm

(0.125 inch) in diameter, the probability of its detection with one caliper run through the

tubing is about 15%.

This probability increases to 80% if the survey is rerun ten times in the same tubing.

Because of the insoluble nature of corrosion products, mechanical calipers may not be able to

determine accurately the extent and degree of corrosion. If the caliper is not able to dislodge

these corrosion products, corrosion may go undetected. Whenever possible, wells with

known scale problems should be acidized before running a caliper survey.

The use of caliper surveys in coated tubing is considered a poor practice. Since the feelers are

hard and press against the tubing with considerable force, damage to the coating can occur.The damage usually occurs at the end of the joint as the feelers spring out into the collar. In

corrosive wells, caliper feelers will remove protective scales and allow corrosion to occur in

the tracks. To prevent this problem, wells are usually treated with an inhibitor after the

caliper survey.

Interpretation of Caliper Data

Consideration of pit depth and general condition of the pipe is usually a better approach than

using a literal pit-by-pit interpretation. Caliper surveys are most valuable when used

comparatively over a period of time.

For example, to determine the effectiveness of a corrosion inhibition program, a background

profile should be run before starting the program. Subsequent caliper surveys should be run

after a suitable time has elapsed as a direct measurement of the progress of corrosion in

subsurface equipment.

Data from caliper surveys can be displayed in various ways. One way is to display the data

from 15 feelers. Figure 6 shows typical caliper tracks with their interpretation. Figures 7A

and 7B show several examples of estimated areas of cross-section.


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FIGURE 6. Typical Caliper Tracks with Interpretation


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FIGURE 7A. Estimated Areas of Cross-section Joints No. 80 and 94


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FIGURE 7B. Estimated Areas of Cross-section Joints No. 83 and 41


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Case Study A

A nondeviated 9,900-foot (3,020-m) North Sea oil well was produced for 27 of the 46 months

that tubing was in the well. Table 2 shows production parameters for this well. The well had

been calipered 30 months after completion and found to have a maximum recorded

penetration of only 10% of the nominalwall thickness. A caliper survey 14 months later

showed a maximum penetration of 60% of the wall. Four months after the second survey, the

tubing had complete penetration. CO2corrosion/erosion had caused this damage. Not even

15 batch inhibitiontreatments over the previous 19 months had proved to be effective.

The worst damage had occurred in the top 6,000 feet (1,830 m) with an estimated average

corrosion rate to failure of more than 120 mil/year (30 mm/a).

Case Study B

Well Location: Offshore Louisiana

Well Data: 2 7/8 inch; 6.5# tubing; 11,500 feet

Problem: The iron count from the salt water in this well indicated a high level ofcorrosion activity but gave no information about location or distribution.Also, tubing failures in this field made a caliper survey advisable.

Solution: The first of two caliper surveys was made in 1984, showing extensiveminor pitting and nine joints with penetrations of more than 40% of wallthickness. In 1987, 2 1/2 years later, the survey showed an increase of116 joints of tubing with at least 40% penetration and a hole in thecentral position of the well.

TABLE 2. Case Study A

Product Quantity

Oil production, B/D 10,500

Water production, B/D 80 to 120

Gas production, MMcf/D 26.0

GOR 2500

Wellhead flowing pressure, psig 1065

Flowing temperature, F 210

CO2partial pressure, psi 96

pH of water-separator sample 4.9 to 5.9

Flowing velocity range 26 to 48 ft/sec

(7.9 to 14.6 m/s)


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Figure 8 shows the wall loss for each joint of tubing in this well. Note the hole at joint 175.

Figures 9 and 10 show cross-sectional drawings of joints 128 and 179, respectively.

FIGURE 8. Case Study B: Wall Loss by Joint


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FIGURE 9. Case Study B: Cross-section of Joint 128

Cross-sectional drawing of Joint 128 showing 23 % area reduction found by 13 of the 15

feelers, illustrating the value of a caliper that records with each feeler simultaneously. This is

a weaker section of pipe than the hole shown in Figure 10.


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Case Study C

Well Location: Inland East Texas


Problem: Monitoring the increase of known H2S corrosion in order to perform aworkover before the tubing fails

Solution: Three surveys were made with the caliper. In 1981, minor pitting wasfound. In 1984, the survey showed corrosion increased from 20% to60% of wall thickness. In 1986, corrosion increased to 80%, alloccurring in the bottom 4,000 feet of tubing in a pattern typical of H2S

corrosion.

Result: After seeing the graph plotted from the 1986 survey (Figure 11), theoperator could see the location and extent of corrosion. He determinedthat he could re-use the upper 7,000 feet of tubing in the well.

FIGURE 10. Case Study B: Cross-section of Joint 179

Cross-sectional drawing of Joint 179 showing the hole by feeler #8. Note that this section of

pipe with 7% area reduction is stronger than the pipe shown in Figure 9.


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FIGURE 11. Case Study C: Wall Loss Versus Tubing Joint Number

(East Texas Field)


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Case Study D

Well Location: Inland South Texas


Problem: This gas well produces 3% CO2and some water, a good indication ofpossible corrosion.

Solution: caliper survey was run. The graph in Figure 12 was plotted from thesurvey data. The confinement of corrosion to the upper 2,800 feet is atypical pattern for CO2corrosion in this well.

Result: After seeing the corrosion profile graph (Figure 12), the operatordecided to back off the tubing at 2,800 feet, pull the corroded tubingabove this depth, and replace it. This decision resulted in substantialsavings on downtime and workover costs.

FIGURE 12. Case Study D: Wall Loss Versus Tubing Joint Number

(South Texas Field)


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HYDROGEN PROBES

Theory of Hydrogen Probes

Hydrogen probes measure corrosion activity by capturing hydrogen released during corrosion

in a well, pipeline, or vessel. Hydrogen dissolves in steel to a significant degree and causes

hydrogen embrittlement, hydrogen blistering, or sulfide stress corrosion cracking. There are

two types of hydrogen probes: the finger probe and the electrochemical patch probe.

The simplest form of a hydrogen finger probe consists of a hollow, thin-walled steel tube that

is sealed on one end and equipped with a pressure gauge and a bleeder valveon the other.

Figure 13 shows the cross-section through a hydrogen finger probe.

A portion of the atomic hydrogen generated by the corrosion reaction diffuses through the

tube wall of a hydrogen probe. This action occurs readily when poisoning agents such as

hydrogen sulfide, cyanide, or arsenic are present. Once inside the probes cavity, hydrogen

atoms combine to form molecules that are too large to diffuse back through the tube wall.This causes the pressure in the tube to increase in proportion to the amount of hydrogen in the

tube. The amount of hydrogen in the tube is a function of the amount of hydrogen generated

by corrosion. A rate of pressure increase greater than about 7 kPa (1 psig) per day indicates

significant corrosion.

A restriction in the probes cavity increases its sensitivity. Typically, the volume of the cavity

is 10 to 15 milliliters. In some cases, a filler rod or an inert fluid is inserted into the cavity.

FIGURE 13. Cross-section of a Hydrogen Finger Probe


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Factors that affect the hydrogen permeation rate include temperature, characteristics of the

steel, scales that build up on the surface, and the environment in which corrosion is taking

place.

Another type of hydrogen probe is the patch probe. The patch probe mounts directly to the

outside of the pipe wall by simple mechanical straps tightened with a screwdriver.

Advantages of patch probes include:

No holes need to be cut into high pressure systems.

Corrosion is measured on the natural inside diameter of the metal wall.

Installation and relocation are simple.

The probe is not subject to fouling, which is a constant problem with most insertion

probes, especially in sour systems.

The measurement is instantaneous minus the short time lag for diffusion through themetal.

With patch probes, atomic hydrogen penetrating the wall causes an electrochemical reduction.

An electronic read-out instrument indicates the relative corrosion rate. Figure 14 illustrates a

typical patch probe.


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FIGURE 14.Patch Probe


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The patch probe has three parts.

Plastic cell body

Acid resistant gasket

Three electrodes (reference, test, and auxiliary)

The cell body is machined to fit the curvature of the vessel to be monitored. The gasket

provides a leakproof seal between the vessel and the probe. The electrolyte used in the cell is

90% H2SO4. A thin piece of palladium foil (0.010 inch), placed on the external vessel wall,

protects the wall from the electrolyte. Palladium is used because hydrogen atoms rapidly

diffuse through it. A layer of wax between the palladium and the vessel provides a

continuous, gap-free medium for the diffusion of hydrogen. The patch probe has a three-

electrode system consisting of a reference electrode, a test electrode, and an auxiliary

electrode.

Patch probes measure the electrochemical reaction caused by the oxidation of hydrogen atoms

to hydrogen ions. A potentiostat holds a constant potential between the reference electrode

and the vessel sufficient to oxidize the hydrogen as it enters the cell. The current required for

this oxidation is recorded and is a direct measure of hydrogen diffusing into the cell. The

more hydrogen diffusing, the more current will be required for oxidation. A one-way vent

prevents the accumulation of hydrogen gas in the probe.

Application of Hydrogen Probes

The hydrogen probe is a qualitative or semi-quantitative tool. It has been most commonly

used in sour systems but has also been used in sweet systems. However, in the absence of

sulfide, the sensitivity of the hydrogen probe is much lower.

Hydrogen probes have been effectively used to monitor corrosion in the following operations.

Gas processing vessels

Gas gathering and transmission lines

Producing wells and crude oil lines Acid systems

Refinery equipment

Hydrogen probes have been used in systems with pressures as high as 7,000 to 9,000 psi.


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Before a hydrogen finger probe is placed in service, it should be degreased and sandblasted.

The probe should also have a small hydrogen pressure to ensure that the probe is not leaking.

The probe has a needle valve for charging with hydrogen. Another method used in the

laboratory charges the probe with hydrogen by immersing the probe element in an acidified

hydrogen sulfide solution.

The placement of a hydrogen probe in very important. Finger probes may be installed in any

position and can be installed in a 1/2-inch (21.3 mm) or larger National Pipe Thread (NPT)

threadolet in a line or vessel. The line or vessel usually must be depressurized when the probe

is inserted or removed. Specially designed hydrogen finger probes, however, allow insertion

and removal from systems under pressure.

All hydrogen probes function in either the liquid or wet vapor phase of a system. The

following locations for hydrogen probes should be considered:

Dead gas areas

High velocity flow gas and impingement points

All locations where water is likely to collect in sour systems (such as suction scrubbersor compressors, separators, water drain lines from dehydrators, and low spots in wet gaslines


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Figure 15 illustrates the exposure of hydrogen probes in four important separate-phase

conditions.

Hydrogen probes are cumulative devices. Hydrogen entry rates must be computed from the

pressure build-up per unit of time. Periodic reading of the probes is necessary.

CAUTION: Probes should never be bled to zero pressure.

A positive pressure indicates that the probe is not leaking, while zero pressure could be

misleading. A hydrogen leak may go unnoticed if the probes gauge is set on zero.

Care should be taken when the pressure gauge approaches its upper limit so that the gauge

will not be ruptured. Operation of the bleeder valve reduces the probes pressure. To operate

the valve, place an index finger over the bleeder valve exit, slightly open the bleeder valve,

vent the hydrogen to the desired pressure, and then close the bleeder valve.

FIGURE 15. Exposure of Hydrogen Probes in Four Phase Conditions


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Hydrogen patch probes can also be used to monitor hydrogen penetration. Following surface

cleaning, a transfer medium (paraffin wax) and a small piece of palladium foil are placed on

the pipe to be monitored. The patch probe mounts over the foil. A pair of gaskets and an

insert, shaped to the general contours of the pipe, provide a leak-tight seal against the foil.

The cell is then filled with the electrolyte. When the palladium foil is polarized, it acts as a

working electrode, oxidizing the hydrogen as it enters the cell of the patch probe. After an

initial pump-down period, the current indicated by the patch probe is directly proportional to

the hydrogen penetration rate.

Limitations of Hydrogen Probes

Both hydrogen finger probes and patches are generally not reliable for a quantitative

indication of the corrosion rate but may be used to detect very rapid corrosion in air-free soursystems. These instruments do not function well in aerated environments. There is no direct

conversion from pressure increase to corrosion rate. Like all other corrosion monitoring

instruments, the hydrogen finger probes are not foolproof. Leaks in the threaded gauge and

valve connections render these probes useless. The bleeder valve can be left open so that no

hydrogen is trapped. If the probes are not checked periodically, pressure can build up and

rupture the gauge.

Frequently hydrogen attack is both highly localized and erratic with respect to time. For

example, in vessels where both liquid and vapor phase are present, hydrogen attack may

occur in only one phase and not the other. Thus, a probe may be located where there is no

hydrogen attack while blistering occurs a short distance away. Probe locations, therefore,should be selected carefully.

Hydrogen finger probes should be inspected regularly for pitting. If pitting is extensive (12 to

14 mils), the probe should be replaced. System pressure can reach the probe cavity if pitting

occurs.

WARNING: If the probe becomes perforated by corrosion, the pressure gauge will

not be isolated from the system. Hazardous conditions for both

personnel and equipment will exist.

Another disadvantage of the hydrogen probe is its sensitivity. In some cases, the pressureincrease is extremely low over a large time interval. Using this type of probe assumes that the

corrosion rate is related to the hydrogen production at the metal-fluid interface, which in turn

is directly related to the hydrogen permeation into the probe. Unfortunately, the hydrogen

probe will not function with polysulfide corrosion which generates no hydrogen.


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Hydrogen probes are not useful in monitoring pitting corrosion in systems where general

corrosion rates are low. These probes are also probably more useful in clean systems such as

gas wells and gas pipelines where scale and paraffin are not a problem.

Interpretation of Hydrogen Probe Data

Probe readings should be taken frequently during the initial operation of a new system. High

probe activity should be followed by an analysis of the system to determine the cause and the

corrective measures to be taken. During the first few days of a new probes exposure, it may

register a high but decreasing indication of hydrogen activity. This occurs during the period

in which the protective sulfide films are forming on the surface of the probe. Sporadic high

rates of activity can be tolerated for short periods, for instance during a process upset, without

fear of causing significant hydrogen blistering damage.

If the hydrogen probe is in good condition and there is no leakage to the atmosphere, lack of a

pressure increase indicates that the corrosive medium surrounding the probe is not causing

hydrogen attack. Conversely, a progressive increase in gauge pressure indicates hydrogen

attack. The pressure in each probe in service should be recorded often enough to show the

rate of pressure rise. When pressure approaches the limit of the gauge, the hydrogen should

be vented, this fact recorded, and the readings continued.

The minimum diffusion rate for significant hydrogen attack is about 0.1 ml/in2/day, which

would cause a pressure rise of roughly 1 psi per day in the most sensitive of the commercially

available probes. However, damage to equipment has been reported when the probes showed

a pressure rise not much over 5 psi per month. A rapid increase in probe pressure indicatesvigorous hydrogen attack. Pressure increases of 25 to 50 psi per day have been observed

under particularly severe attack.

Pressure in a hydrogen probe will usually rise rapidly or not at all. Consequently, what rate of

increase represents the borderline of damage and freedom from attack is not well defined.

The possibility of hydrogen damage to equipment should be considered whenever a steady

increase in probe pressure is noted, regardless of the rate of increase. The rate of pressure

increase is a guide to the urgency of inspecting the equipment.


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Case Study A: Sour Amine Systems

Hydrogen build-up rates of 40 psi per day have been observed in some very corrosive sour

amine systems. Field experience has shown that corrosion in a sour system is minimal when

the rate of the hydrogen probes pressure increase is 1 psi per day or less. For 3 years prior to

the installation of hydrogen probes in a sour gas sweeteningsystem, corrosion had occurred

in the amine reboiler, reclaimer, and regenerator tower. Figure 16 shows hydrogen probe data

obtained from this system. A hydrogen probe installed in a lean amine line recorded an

average pressure increase of about 20 psi per day for a period of four months. Make-up water

periodically added to the amine was found to contain oxygen. In February, the make-up

water was deaerated. The hydrogen pressure build-up dropped to an average of about 5 psi

per day. During April, the source of the deaerated water was out of service. The corrosion

rate as indicated by the probe increased drastically.

FIGURE 16. Case Study A: Sour Gas Plant Hydrogen Probe Data


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Case Study B: Sour Gas Injection

Both hydrogen probes and corrosion coupons were used to monitor corrosion rates and

inhibition effectiveness in a sour gas injection project. Gas used for injection consisted of

both H2S and CO2. The gas was compressed in four stages from 10 psi to 1200 psi. Between

the third and fourth stages of compression, the gas was dehydrated. Hydrogen probes,

coupons, and inhibitor injection points were located between each stage of compression and

at the injection wells. Figure 17 shows the hydrogen probe data for the third stage

compressor discharge scrubber. During the first three weeks of operation, the pressure in the

probe increased to 24 psi. During the second and third week, the rate of pressure build-up

declined as a protective film of iron sulfide formed on the probe. When inhibitor treatment

was started, the rate of pressure build-up in the probe dropped to zero. After about three

months, the corrosion injection pump on the third stage discharge line malfunctioned. Due to

lack of an inhibitor, corrosion soon increased as shown by the build-up of hydrogen pressure

in the probe as shown in Figure 17. After the inhibitor pump was repaired, the hydrogenpressure build-up decreased again. Coupons in this same line were free of corrosion and,

therefore, were not able to detect the very slight corrosion shown by the hydrogen probes.

FIGURE 17. Case Study B: Hydrogen Probe Data for

Third Stage Discharge in Sour Gas System


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Case Study C: West Texas Oil Well

Two oil wells in west Texas, pumped continuously, were monitored by both a finger probe

and a patch probe located in a flowline bypass near the well head. These probes evaluated

inhibitors. Following a normal batch treatment of the well, the well fluids were directed

through the bypass so that the probes could freely corrode. Output of the probes was

recorded continuously, while weight loss coupons were placed in the same bypass to permit

correlation with the hydrogen probe data. After one week, the inhibitors that produced the

lowest and next-to-lowest average corrosion rate also produced the lowest and and next-to-

lowest hydrogen probe response.

Case Study D: Inhibitor Testing on an Absorption Tower in an FCC Gas Recovery

System

The hydrogen patch probe has been used to select the most effective inhibitor and to optimize

the inhibitor addition rates. The results of an inhibitor test on an absorption tower are shown

in Figure 18. The patch probe rates are on the left and the inhibitor concentrations are on the

right. The results are inverted so that low inhibitor concentrations would correspond to high

hydrogen rates and vice versa.

FIGURE 18. Case Study D: Hydrogen Patch Probe Data

From An Inhibitor Test on An Absorption Tower


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This absorber was a large tower with the gas feed entering about one-third up from the

bottom. Lean oil entered the top of the tower along with the corrosion inhibitor. The

hydrogen patch probe was located near the gas feed in an area that had shown the most severe

hydrogen blistering and cracking during inspection. The lean oil was partially recirculated

after stripping, resulting in partial recirculation of the inhibitor and continued inhibitor

residuals after injection had stopped.

The absorber tower was being inhibited with 10 ppm of a water soluble inhibitor. The patchprobe readings dropped to almost 2 a, which is a very low level of hydrogen activity. Onthe eighth day after installation of the patch probe, the inhibitor injection was stopped. Fivedays later, the patch probe responded with an increase in hydrogen activity. By varying theinhibitor concentration and monitoring the hydrogen activity with a patch probe, the optimumconcentration of inhibitor could be determined.

The use of a patch probe allowed the monitoring of a vessel that had no other means ofmonitoring, for example, no water sample points, no workable pressure probes, and no entry

for coupons. In addition, the use of the hydrogen patch probe allowed the operator to select

the optimum concentration of the inhibitors tested.


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Case Study E: Gas Well Flowline

A hydrogen patch probe was used on a flowline of a gas well that produces about 10MMCFD of 0.15% H2S, 20% CO2with about 1,000 B/D of condensate, and 150 B/D of

brine. Flowline conditions were 125 F and 1,000 psi. While iron counts had beensuccessfully used to determine inhibitor retreatments on this well, the operator wanted to seeif the patch probe could give identical data. As Figure 19 shows, the patch probe datacorrelated well with iron count data.

FIGURE 19. Case Study E: Hydrogen Patch Probe Data and Iron Counts

From Mildly Sour Gas Well


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Case Study F: Absorber Tower in Gas Plant

Experience on this tower had shown weld cracking, extensive internal hydrogen blistering,

and loss of trays and caps due to metal loss, particularly toward the lower part of the tower.

This problem was believed to be due to the dilution of corrosion inhibitor by two additional

feed streams in the lower section. The environment consists of FCCand coker gas with low

percentage amounts of H2S and NH3, trace amounts of HCN, and water. The patch probe

was located opposite the lower tray.

The overall response of the patch probe has varied from 1 to over 300 a. Patch probe data isshown in Figure 20. This data shows that at a feed rate of 25 to 30 gallons per day of aneffective inhibitor, patch probe reading are 1 to 2 a. At an inhibitor feed rate averaging3 gallons per day, the reading rose slowly to 25 a and then stabilized at 18 to 20 a when theinhibitor was increased to 10 gallons per day. A switch was made to another inhibitor thatwas suspected to be of inferior quality. With an inhibitor concentration of 30 gallons per day,

the patch probe readings rose slowly at first and then rapidly rose to 300a. A return to themore effective inhibitor, first at 30 gallons per day, then at 15 gallons per day, lowered theprobe reading to 10 to 12 a in a few days.

FIGURE 20. Case Study F: Hydrogen Patch Probe Data

From Absorber Tower in Gas Plant


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Case Study G: Slightly Sour Waterflood System

A hydrogen patch probe was mounted in a slightly sour waterflood flowline 30 feet upstream

of some weight loss coupons. This 3-inch diameter flowline operated at an injection pressure

of 1,000 psi with the composition of injection water as shown in Table 3. Note that the

sulfide content of this water is very low (0.8 mg/liter).

In order to compare the hydrogen current levels to the weight loss coupon corrosion rates, the

hydrogen current levels were averaged. Figure 21 shows the average weekly current levels in

microamps compared to the average weekly coupon rates in mils per year (mpy). The

correlation is virtually 100% for the first three months. Starting on April 1, this correlation

ended, and the hydrogen patch probe gave erratic results. This problem was traced to oxygen

entry.

TABLE 3. Composition of

Injection Water (pH = 7.1)

Compound mg/liter

Sodium 9,200

Ammonium 190

Calcium 490

Magnesium 425

Barium 39

Iron 0.8

Sulfate 24

Chloride 16,100

Bicarbonate 940

Borate 100

Silica 97

Sulfide 0.8


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FIGURE 21. Comparison of Average Weekly Corrosion Rate and H2Current


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ULTRASONICS

Theory of Ultrasonics

Ultrasonictesting is a nondestructive method of determining wall thickness or the location of

flaws within any material capable of conducting sound. The general principles used in

ultrasonic testing are quite similar to sonar and radar echo-ranging techniques developed

during World War II.

Ultrasonic waves are generated by a device called a transducer. Transducers are crystals that

exhibit a phenomenon known as the piezoelectric effect, which transforms electrical pulses

into mechanical vibrations and mechanical vibrations into electrical pulses. A rapidly

fluctuating voltage will cause the transducer to vibrate at the same frequency as that with

which the voltage fluctuates, producing an ultrasonic sound wave. Ultrasonic equipment uses

conventional echo-ranging instrumentation and incorporates electronic circuits for thegeneration of signals. Various types of transducers convert the sound echoes into the

mechanical vibrations (sound) and reversibly convert the sound echoes into electrical voltage

pulses. Additional circuitry then amplifies the weak returning signals and displays them on

the data read-out device. This may either be a cathode-ray oscilloscopeor a meter or digital

thickness read-out.

For testing, ultrasonic vibrations of the transducer are generally introduced into the material

through a couplant such as oil, grease, glycerine, or water. Within the test material, the

ultrasonic waves produced by the sending transducer are beamed waves that progress

almost as a column, like light from a flashlight. These sound waves will reflect from various

boundaries within the part, similar to the reflection of light rays from reflecting surfaces suchas mirrors. These reflected sound waves return to the transducer, causing it to vibrate and

send an electrical signal to the instrument. The total time elapsed from when the electrical

signal is sent to the transducer until the reflected signal is returned is electronically measured

on a cathode-ray tube (CRT) and empirically converted to either thickness or distance from a

reflecting defect.

Figure 22 illustrates the principle of straight-beam ultrasonic nondestructive testing.

Figure 22(a) represents the propagation of sound within a test specimen that does not contain

any flaws. A typical CRT screen presentation (Figure 22(b)) is illustrated to show the initial

pulse, time base line, and back reflection. Figure 22(c) represents the propagation of sound

within a test specimen containing a known flaw. Note the flaw indication shown on the CRTscreen display (Figure 22(d)).


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Angle-beam or shear-wave ultrasonic testing can be defined as testing in which the sound

beam is sent into the test piece at an angle, using a type of ultrasonic sound wave known as

shear wave. Angle-beam testing is used to locate flaws or cracks that are not oriented

properly in the test piece to be located by means of straight-beam tests. This method of

testing is most favorable for weld inspection. Figure 23 represents ultrasonic examination of

welded test specimens using the angle-beam (or shear-wave) method of sound propagation.

Note the angular position of the transducer within the wedge in Figure 23(a). The CRT screen

presentation (Figure 23(b)) illustrates the initial pulse of sound produced by the transducer in

a welded test specimen that does not contain any flaws. The absence of the back reflection,

which indicates material thickness and is usually visible in straight-beam tests, is attributed to

the angle of the sound beam. A welded test specimen containing a known flaw is illustrated

in Figure 23(c). Note the transducer position and the distance between the transducer and the

weld area. The flaw indication as illustrated on the CRT screen display is shown in

Figure 23(d).


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FIGURE 22. Principle of Straight-beam Ultrasonics


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FIGURE 23. Principle of Angle-beam or Shear-wave Ultrasonics


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Application of Ultrasonics

Ultrasonic testing can be used to determine wall thinning, pitting, erosion, and flaws in

metals, plastics, and rubbers. Today ultrasonic testing is used mostly in the steel industry and,

to a lesser extent, in concrete inspection and medical examinations.

In Saudi Aramco, ultrasonic testing monitors the condition of operating systems by

determining the rate of reduction in wall thickness due to erosion (mechanical wear) or

corrosion (chemical wear).

Ultrasonic testing can also be used to measure the changes in structure that can occur in

certain materials due to factors such as high temperature and hydrogen penetration.

New, improved models are introduced each year by manufacturers but there are several

instruments now available that perform well. In order to select the proper equipment, therequirements for each application should be evaluated. Many factors determine the best

choice of an ultrasonic instrument for a specific application.

The use of ultrasonics for inspection, maintenance, corrosion monitoring, and quality

assurance/control work is rapidly expanding. Ultrasonics has proven to be a fast, accurate

method for nondestructively obtaining wall thickness measurements of plant/production

equipment and piping, both during a turnaroundand while a plant or production unit is on-

stream.

Limitations of Ultrasonics

Understanding where to expect corrosion in equipment such as towers, drums, heat

exchangers, and piping is essential to successful ultrasonic corrosion monitoring. Figures 24

through 27 illustrate typical locations where corrosion would be most likely to occur in a

piping system.

The main limitation of ultrasonic inspection is the large number of readings required to

determine the general condition of the material. Other limitations of ultrasonics include:

Pitting corrosion is not easily located.

Readings must be taken over a period of time to determine the corrosion rate. High temperature measurements may have to be adjusted.

Surfaces must be free of scale or other foreign substance such as liquids (except for thethin film of couplant required for signal transmission).

Exact orientation of the detector probe (transducer) is required in order to obtainreproducibility.


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Interpretation requires a trained operator.

FIGURE 24. Typical Corrosion Monitoring of a Reducer


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FIGURE 25. Typical Corrosion Monitoring of a Tee


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FIGURE 26. Typical Corrosion Monitoring of an Elbow


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FIGURE 27. Typical Corrosion Monitoring of a Pipe


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Interpretation of Ultrasonic Data

The overall accuracy of ultrasonic measurements is a function of several variables including

temperature. The higher the surface temperature, the greater the potential for error due to

material expansion and a lower acoustic velocity. The engineer must take this into account

and adjust the readings downward to determine actual wall thickness.

Readings must be taken over a period of time to determine the corrosion rate. A skilled,

experienced operator using a properly calibrated instrument should obtain consistently

accurate measurements to within 0.010 inch under field conditions.


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RADIOGRAPHY

Theory of Radiography

Radiography is a technique using differential absorption of a radiation source to inspect

welds or detect corrosion. Radiography can determine the wall thickness of pipe as well as

detect pitting or other localized corrosion damage. A source emits radiation through a test

area. Variations in thickness, composition of the material, and wavelength of the radiation

will cause different amounts of the radiation to be absorbed. The unabsorbed radiation is

collected and correlated to a wall thickness. Photographic film or a fluorescent screen placed

adjacent to a solid body on the side opposite the source of radiation thereby shows an image

of subsurface defects as illustrated in Figure 28. Cracks, voids, inclusions, and other defects

can be detected by radiography as shown in Figure 29. The more radiation penetrating the

object and striking the film, the darker the film appears when developed.

FIGURE 28. Production of a Radiological Image


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The developed film, called a radiograph, provides positive visual evidence of defects and

corrosion damage. The amount of radiation that passes through a metal in a given length of

time is inversely proportional to its thickness. This means that more radiation will pass

through a thinned, corroded area than through a thicker, undamaged area. Therefore, pits or

corroded areas show up as dark spots or areas on a radiograph.

X-ray equipment is portable but bulky and requires electrical connections in order to operate.X-ray equipment is normally used for the inspection of thin material, 0.125- to 0.750-inch

steel. However, gamma ray radiography is the most widely used method for field inspection.

The most widely used gamma radiographic sources are iridium-192 and cobalt-60. Iridium-

192 is used for material thickness of 0.250 to 3.500 inches for steel. Cobalt-60 is used for

material thickness of 2.50 to 8.00 inches for steel. Gamma sources do not require electrical

connections and are much smaller than X-ray machines.

FIGURE 29. X-rays Reveal Defects in MaterialUnder Inspection


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There are two basic types of radiographic inspection: manual and real-time radiography.

Manual radiography collects the unabsorbed radiation on sensitive film. In real-time

radiography, the image is sent directly to a viewing screen or television monitor and may be

taped for future viewing. With real-time radiography, the test piece can be manipulated

during inspection to achieve the proper orientation for flaw detection.

Application of Radiography

Radiography allows inspection of selected key areas in a system without shutdown. For

example, selected areas in a flowline might include elbows, restrictions, or other places where

higher corrosion rates are expected. It is usually not economical to inspect 100% of a system

with radiography. Therefore, selection of the test sites is critical. Radiography has been used

for many different types of inspection including:

Measuring pipe and tube wall thicknesses, both on-stream and during shutdowns, withor without insulation

Checking plugged lines and measuring scale or coke thickness

Evaluating the effectiveness of chemical cleaning in scaled furnace tubes

Measuring pit depth in pipelines by film density differences

Examining valves for explanations of malfunctions such as those caused by brokenstems, corroded seats, broken springs, etc.

Evaluating small diameter, threaded pipe nipple fit-ups and measuring internal corrosion

Externally examining a column for evidence of tilted or missing trays

Thus radiography provides a permanent, visible record of the internal condition of a material.

Radiography can be used with all materials and is independent of the magnetic and electrical

properties of the material. Using special X-ray tubes, it is also possible to examine objects

that are moving rapidly, for instance, motors.


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Interpretation of Radiographic Data

The presence of pitting in piping is distinguished by a mottled or black appearance. Pit

depth can be estimated by the density differences. For comparison, sample pipes can be

prepared with holes (representing pits) drilled to different depths. Test radiographs can then

made and the film densities at the pits accurately measured with a film densitometer. A plot

of pit depth versus film density (for equal background densities) thus enables an accurate

estimate to be made of the depth of unknown pits.

Radiographs should be viewed in an area with subdued lighting to minimize reflections from

the viewing surface. Radiographic film images are usually viewed on an illuminated screen.

The viewing apparatus should have an opal-glass or plastic screen large enough to

accommodate the largest film to be interpreted. The screen should be illuminated from

behind with light of sufficient intensity to reveal variations in photographic density.

Radiographic coverage, which refers to the percentage of area or volume of a test piece thatappears in a radiograph or series of radiographs, must be evaluated to ensure that all regions

of the test piece have been radiographed with adequate clarity.


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AC IMPEDANCE

Theory of AC Impedance

With linear polarization techniques, the corrosion resistance between two electrode surfaces is

measured via the solution and any deposits or film present on the surface. Erroneous results

are often obtained due to the low conductivity of the environment and lack of dynamic

response due to absorption or diffusion. A DCmeasurement assumes that steady state can be

achieved during this measurement. This steady state is often not possible to achieve because

of the electrode interfacial impedance or the polarization resistance.

The overall impedance at a metal/electrolyte surface is due to the following factors:

The ionic and electronic resistances of the solution and the bulk of the electrode film

The capacitance of the film and solution

The charge transfer resistance arising from the anodic and cathodic electrochemicalreactions

The use of ACcurrent allows the charge transfer resistance to be determined by a method that

eliminates the ionic and electronic resistance of the solution and the bulk of the electrode film.

This action represents a distinct advantage over linear polarization techniques and

substantially reduces the interference of solution conductivity and surface films and deposits.

Application of AC Impedance

AC impedance probes measure the electrical resistance of a brine solution between two

electrodes in a system when a prescribed AC voltage difference is applied between the

electrodes. In theory, the measured solution resistance will increase when an effective

corrosion inhibitor film is established on the electrode surfaces. Adequate corrosion

protection is inferred from the presence of the corrosion inhibitor film. Typically, an

insulated electrode installed in a fitting and the pipe wall itself are used as the electrodes.

Limitations of AC Impedance

User experience indicates that the AC impedance measurement does not correlate with

observed corrosion in field systems. Significantly higher inhibitor concentrations are required

to increase inhibitor film resistance than are required for corrosion protection. Nevertheless,

AC impedance probes have been successfully used to monitor high inhibitor concentrations

such as returns from downhole inhibitor treatments or erratic inhibitor injection pump

operations.


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SAND PROBES

Sand may cause very serious and costly problems.

Production loss caused by sand bridging in casing, tubing, or flowlines

Failure of casing or liners from removal of surrounding formation

Abrasion of downhole and surface equipment

Handling and disposal of formation materials

Tubulars are frequently eroded severely by sand entrained in produced fluids. Large holes

can occur in slotted liners. When extensive erosion occurs and is combined with a high axial

load, severe crimping of the tubulars may occur. In addition, surface equipment is also

subject to sand damage particularly at or near changes in cross-sectional area or direction.

Theory of Sand Probes

Originally sand probes were used as safety devices for early warning of hazardous conditions.

These probes are thin-walled, hollow-steel cylinders with a closed end and are installed

perpendicular to flow at one or more locations in the surface piping. When the probe wall is

penetrated by sand erosion, the flow stream pressure is transferred to a pilot valve to either

shut-in the well or signal a monitoring action. These probes have been manufactured in

various metals and wall thicknesses. Figure 30 illustrates several schematics of these probes.

A different type of sand probe is a radioactive probe. Both radioactive material and the

associated radiation monitoring are needed for this monitoring.

Another sand probe is the sonic probe. It is mounted in a surface flowline where acoustical

pinging of sand is converted to an electrical probe output signal that can be calibrated to

determine solids concentration in pounds per day or grams per second as a function of fluid

velocity. Sand concentration as low as 10 pounds per 1000 barrels at flow velocities as low

as 3 feet per second have been detected by the sonic sand probe. Unfortunately, accuracy and

sensitivity are reduced if solids, such as silts, are very fine and if the flow system is liquid

with severe gas slugging. These monitors are easily installed, clamp-on instruments featuring

continuous monitoring. Suitable placed acoustic emissions (AE) transducers are used formonitoring acoustic emissions created by sand particles colliding with the inner surface of the

pipe.


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Application of Sand Probes

Sonic sand probes can determine a wells maximum sand-free production rate. With this

technique, the effectiveness of various completion, simulation, and production practices may

be established and maximum production maintained. Continuous monitoring in surface

flowlines permit corrective action to be taken before excessive erosional damage occurs.

These corrective actions can range from changing the choke size to packing the well with

gravel.

Sand probe used in surface flowline to detect entrained sand in well flow features a thin-

walled, closed probe that transmits well pressure when erosion penetrates probe wall A. Twosignal transmitting systems are used in conjunction with protective well shut-in devices or

monitors. In B, high well pressure actuates a 50-psi pilot valve. C schematically represents

an integral pressure signaling unit in which high well pressure moves an internal piston

outward to bleed off pilot pressure to atmosphere and actuate pneumatic controls. Plunger

extension also gives visual indication of cut probe.

FIGURE 30. Sand Probes


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LIST OF ARTICLES

The Art of Borescope Photography

The New Kinley Microscopic Caliper

Kinley and Worldwide Affiliates Services: The Kinley Microscopic Caliper

Multi-Finger Caliper from Schlumberger

Monitoring Internal Corrosion in Oil and Gas Production Operations with HydrogenProbes

Hydrogen Probe Calibration and Temperature Corrections

Hydrogen Probes

Corrosion Monitoring with Hydrogen Probes in the Oilfield

Hydrogen Penetration Monitoring System


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GLOSSARY

AC Alternating current; an electric current that reverses its direction

at regularly recurring intervals

bleeder valve A small valve used to draw samples or vent air; also known as

sample valve

borescope A rigid type of endoscope; an instrument used for the visual

inspection of hard-to-reach locations

brine Sale water; specifically, liquids found in sedimentary basins;

oilfield or produced water

caliper A device with spring-loaded arms that press against the wall of atubing or casing used to detect and measure any change in the

pipe diameter

collar A tubing or casing coupling; a pipe fitting with threads on the

inside used for joining two pieces of threaded pipe of the same

size

couplant A material used to transmit a sound wave generated by a

transducer to a test specimen during ultrasonic inspection

DC Direct current; an electric current that flows in one direction onlyand is substantially constant in value

drums Metal cylinders used as equipment in process systems

endoscope An instrument used to visualize the interior of tubes or

equipment such as engines

FCC Fluid catalytic cracking; an oil refining process in which the gas-

oil is cracked by a catalyst bed fluidized by using oil vapors

feelers Spring-loaded arms or fingers used as sensors in calipers

fiber optics A bundle of thin transparent fibers of glass or plastic that

transmit light throughout their length by internal reflection

fiberscope A flexible type of endoscope; an instrument used for the visual

inspection of hard-to-reach locations


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flaws Defects or imperfections in a material; hidden faults that may

cause failure of a material under stress

fluorescent Bright and glowing as a result of emission of electromagnetic

radiation; usually as visible light resulting from and occurring

only during the absorption of radiation from some other source

gas sweetening The process of removing hydrogen sulfide, carbon dioxide, and

other impurities from sour gas

inhibition Control or prevention of corrosion and/or scale using chemical

inhibitors

nominal Relates to a designated or theoretical size that may vary from the

actual

oscilloscope An instrument in which the variations in a fluctuating electrical

quantity appear temporarily as a visible wave form on the

fluorescent screen of a cathode ray tube

piezoelectric effect Involves a phenomenon that transforms electrical pulses into

mechanical vibrations and mechanical vibrations into electrical

pulses

prism A transparent body bounded in part by two nonparallel plane

faces that is used to disperse a beam of light

radiograph Positive visual evidence of defects and corrosion damage shown

on developed film from radiographic inspection

radiographic coverage percentage of area or volume of a test piece that appears in a

radiograph or a series of radiographs

radiography Technique using differential absorption of a radiation source to

inspect welds or detect corrosion

stripping The process of removing contaminants from a process materialsuch as oil and condensate

stylus A hard pointed, pen-shaped instrument used for marking on

paper or metal


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telescope A tubular magnifying optical instrument; an optical instrument

used for viewing distant objects by means of the refraction of

light through a lens or reflection of light rays by a concave

mirror

turnaround Planned, periodic inspection and overhaul of the units of a

production system; preventive maintenance and safety check

requiring the shutdown of process or production equipment

ultrasonics A nondestructive technique that uses the transmission of high

frequency sound waves into a material to detect imperfections

within the material or changes in material properties

wireline A cable made of strands of steel wire used to lower and raise

devices and gages in wellbores; used for logging instruments andbottomhole pressure gages

workover Operations on a well to restore or increase production or

injectivity; also to effect a repair work on a well

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