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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
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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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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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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
Well Data: 2 3/8 inch; 4.7# tubing; 12,200 feet
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
Well Data: 2 3/8 inch; 4.7# tubing; 9,100 feet
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