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CORROSION CONTROL 179
Figure 6.88 Stray current corrosion on an unprotected line
crossing a cathodically protected line. The arrows show current
paths from the anode bed through the nearest portion of the
foreign line and then leaving the foreign line near the pro-
tected line and causing corrosion.
Rectifier
+
–
Foreign Line
Protected Line
Figure 6.89 Whitish deposits underneath debonded fusion -
bonded epoxy coating. Photo courtesy of R. Norsworthy,
Polyguard Products, Inc.
galvanic anodes can also be attached near the location
where interference is occurring. These anodes can have
the effect of shifting the potential to a protected level.
It is also possible to use insulating joints or to adjust the
output of the “ offending ” rectifi er to a level where the
stray current is reduced. Improvements in the coating
on the foreign line are also helpful.
123
Stray current effects may also be due to natural elec-
tromagnetic phenomena. Telluric currents can be identi-
fi ed by recording the pipe - to - soil potential for 24 h. If
no recognizable pattern is identifi able, then the currents
are probably not man - made and are telluric. These “ tel-
luric currents ” can have a number of causes, but they
normally have minimal effect on corrosion because they
usually do not last very long.
123
Debonded Coatings Coating debonding can be caused
by excessive cathodic protection or by inadequate
coating - to - metal adhesion, which is usually due to poor
surface preparation prior to the coating process.
Excessive cathodic protection can cause hydrogen
gas evolution at the metal - coating interface. Gas pres-
sure buildup eventually leads to coating debonding. This
was shown in Figure 6.72 . Some organizations try to
avoid hydrogen blistering by limiting the negative
potentials allowed for cathodic protection, but the
current density at the metal surface is more important.
Water is only stable over a 1.23 V range between oxygen
evolution at anodes and hydrogen evolution at cath-
odes. International standards for testing coatings for
cathodic debonding resistance use galvanic anodes to
test for this phenomenon, and these galvanic anodes can
achieve high current densities near coating holidays but
very limited potentials. Cathodic protection also shifts
the pH at cathodes to more alkaline (higher pH) values,
and some coatings are not resistant to debonding in the
presence of alkalis.
Coating debonding due to poor surface preparation
is shown in Figure 6.89 , where an FBE coating has lifted
from the surface. The metal underneath the debonded
coating is discolored, but no signifi cant corrosion has
occurred. The whitish deposits underneath this dis-
bonded coating show that cathodic protection has
reached the metal surface, increased the pH of the mois-
ture at the metal – environment interface, and caused
these mineral deposits, similar to those shown in Figure
6.66 .
Debonded coatings lifted away from the metallic
substrate can act as dielectric shields preventing cathodic
protection currents from reaching the shielded metal
surface, and the unprotected metal surface can corrode.
FBE coatings have the reputation for not causing this
kind of shielding. Other commonly used pipeline coat-
ings do shield the metal surface and allow corrosion to
occur as is shown in Figure 6.90 . This pipeline, which had
substantial areas of debonded coatings, was found to be
corroding along much of the pipeline, even though
cathodic protection was applied and above - ground
pipe - to - soil readings indicated that the structure was
cathodically protected.
Dielectric shielding masks the problems of corrosion
underneath the coating, and this unprotected area
cannot be identifi ed by potential measurements using
close interval surveys or other commonly used over - the -
ground pipeline inspection techniques. This type of
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180 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION
coating disbonding can increase cathodic current
demand by increasing the total surface area of uncoated
metal.
124
Misapplication of Galvanic Anodes on Small
Underground Storage Tanks Many owners of under-
ground storage tanks are small operators with no pro-
fessional corrosion staff or experience. The Steel Tank
Institute in the United States developed STI p3 tanks
to meet this market (Figure 6.91 ). They are sold with
three methods of corrosion control:
•
Electrical isolation from pumps and other stray
current sources
•
Protective coatings as the primary means of corro-
sion control on the buried tank exterior
•
Prepackaged galvanic anodes intended to prevent
corrosion at coating holidays
Unfortunately, the cathodic protection systems are mar-
keted with a misunderstanding of why different galvanic
anodes are chosen. The STI website states:
125
5.0 ANODE INTEGRITY
5.1 STI - P3 tanks may be equipped with either zinc or
magnesium anodes. Whereas magnesium anodes are
designed only for installation in soil resistivities of
2000 ohms - cm or greater, zinc anodes are effective in all
soil resistivities
Most managers, having no background in cathodic
protection, will choose the zinc anodes based on the
recommendation that they are “ effective in all soil
resistivities. ”
This recommendation on the use of zinc anodes is the
reverse of most recommendations on the use of zinc
anodes. These tanks are not sold with anode backfi lls, so
the natural resistivity of the local soil will determine the
corrosion rate of the anodes, and zinc anodes cannot be
effective in high - resistivity soils.
The lessons to be learned from this situation are:
•
STI - P3 tanks are sold with inappropriate cathodic
protection systems.
•
What appears to be an industry standard may be a
marketing organization recommendation.
•
Industry standards and marketing organizations
can contain mistakes.
Above - ground storage tanks have many advantages,
including ease of inspection, for many oil and gas
production operations.
Summary of Cathodic Protection
Cathodic protection is a widely used means of lowering
corrosion rates. The early advocates of cathodic protec-
tion usually did not claim perfect protection, merely a
reduction in leaks. While cathodic protection has
lowered corrosion rates on oil and gas production struc-
tures for many years, it cannot stop all corrosion, and all
cathodic protection systems must be periodically
inspected to insure that they are working correctly.
Standards for Cathodic Protection
The list below shows some of the international
standards relevant to cathodic protection. These are
Figure 6.90 Pitting due to debonded coating which shielded
cathodic protection current. Photo courtesy of R. Norsworthy,
Polyguard Products, Inc.
Figure 6.91 STI - P3 tanks in storage prior to installation.
c06.indd 180c06.indd 180 10/29/2010 10:35:59 AM10/29/2010 10:35:59 AM
CORROSION CONTROL 181
consensus standards based on industrial practice at the
time of publication and are reviewed and revised on a
periodic basis. The current version of the standard
should always be used. As one example, NACE SP 0169 -
2007 is the 2007 version of a standard that originated in
1969. Signifi cant changes have been introduced into this
and many other standards. While earlier versions of
these standards are sometimes diffi cult to obtain, it is
important to recognize that existing equipment and
systems may refl ect earlier versions of standard indus-
trial practice. Earlier versions of these standards can be
obtained from technical libraries and from the issuing
organization. Most current standards can be down-
loaded from the Internet.
NACE Standards
•
SP0169, Control of External Corrosion on
Underground or Submerged Metallic Piping
Systems
•
SP0176, Corrosion Control of Submerged
Areas of Permanently Installed Steel Offshore
Structures Associated with Petroleum Produ-
ction
•
RP0177, Mitigation of Alternating Current and
Lightning Effects on Metallic Structures and
Corrosion Control Systems
•
SP0186, Application of Cathodic Protection for
External Surfaces of Steel Well Casings
•
RP0193, External Cathodic Protection of On -
Grade Carbon Steel Storage Tank Bottoms
•
RP0286, Electrical Isolation of Cathodically
Protected Pipelines ”
•
RP0285, Control of External Corrosion on Metallic
Buried, Partially Buried, or Submerged Liquid
Storage Systems
•
RP0286, Electrical Isolation of Cathodically
Protected Pipelines
•
RP0388, Impressed Current Cathodic Protection of
Internal Submerged Surfaces of Steel Water Tanks
•
RP0675, Control of External Corrosion on Offshore
Steel Pipelines
•
TM 0497, Measurement Techniques Related to
Criteria for Cathodic Protection on Underground
or Submerged Metallic Piping Systems
ASTM Standards
•
ASTM G 8, Cathodic Disbonding of Pipeline
Coatings
•
ASTM G 19, Cathodic Disbonding of Pipeline
Coatings by Direct Soil Burial
•
ASTM G 42, Standard Test Method for Cathodic
Disbonding of Pipeline Coatings Subjected to
Elevated Temperatures
•
ASTM G 95 “ Test Method for Cathodic
Disbondment Test of Pipeline Coatings (Attached
Cell Method)
DNV Standards
•
DNV - RP - B401, Cathodic Protection Design
•
DNV - RP - F103, Cathodic Protection of Submarine
Pipelines by Galvanic Anodes
British Standards
•
BS 7361 - 1, Cathodic Protection
•
EN 12068, Cathodic Protection. External Organic
Coatings for the Corrosion Protection of Buried or
Immersed Steel Pipelines Used in Conjunction
with Cathodic Protection. Tapes and Shrinkable
Materials
•
EN 12473, General Principles of Cathodic
Protection in Seawater
•
EN 12474, Cathodic Protection for Submarine
Pipelines
•
EN 12495, Cathodic Protection for Fixed Steel
Offshore Structures
•
EN 12499, Internal Cathodic Protection of Metallic
Structures
•
EN 12696, Cathodic Protection of Steel In
Concrete
•
EN 12954, Cathodic Protection of Buried or
Immersed Metallic Structures. General Principles
and Application for Pipelines
•
EN 13173, Cathodic Protection for Steel Offshore
Floating Structures
•
EN 13174, Cathodic Protection for Harbour
Installations
•
EN 13509, Cathodic Protection Measurement
Techniques
•
EN 13636, Cathodic Protection of Buried Metallic
Tanks and Related Piping
•
EN 14505, Cathodic protection of complex
structures
•
EN 15112, External Cathodic Protection of Well
Casing
•
EN 50162, Protection against Corrosion by Stray
Current from Direct Current Systems
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182 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION
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122 B. Cherry . 2006 . How instant is instant? Journal of
Computer Science and Engineering . 9 : 6 .
123 M. J. Szeliga . 2000 . Stray current corrosion . In Peabody ’ s
Control of Pipeline Corrosion , 2nd ed. , ed. R. Bianchetti ,
216 – 241 . Houston, TX : NACE International .
124 A. Toncre and N. Ahmed . 1980 . Cathodic protection
in crevices under disbonded coatings . Materials
Performance . 20 ( 6 ): 39 – 43 .
125 Steel Tank Institute . 2007 . Cathodically protected under-
ground storage tanks, intallation instructions, R821 - 07 .
https://www.steeltank.com/LinkClick.aspx?fi leticket
=nVIaCe49tgU%3d & tabid=108 & mid=502 (accessed
September 18, 2010).
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7
INSPECTION, MONITORING, AND TESTING
The concepts of inspection, monitoring, and testing
often overlap, and many organizations have slightly dif-
ferent defi nitions of the terms. For the purposes of this
book, the following ideas will be used to differentiate
between the various terms:
•
Inspection is used to determine the condition of a
system.
•
Monitoring is used as a tool for assessing the need
for corrosion control or the effectiveness thereof.
•
Testing has two oilfi eld defi nitions. Hydrostatic
testing involves fi lling a structure with liquid to
determine if it has an adequate strength to with-
stand the desired stresses or pressures, which often
involve code - mandated safety factors. Other tests
are performed to determine the suitability of equip-
ment, materials, chemicals, and so on for use in
fi eld applications. These tests are often performed
in laboratories, but may also involve fi eld trials.
The equipment involved in oilfi eld production is so
large and complicated that inspections and monitoring
procedures must be selected in a cost - effective manner
to insure safe and effi cient operation. It is important to
recognize that not every process can be inspected, mon-
itored, or tested before or during operation. The Pareto
principle, often expressed as the idea that approxi-
mately 80% of all problems come from 20% of the
equipment involved, or the concept of the “ insignifi cant
many and the mighty few, ” has been used by many
organizations to prioritize inspection, monitoring, and
testing.
1 – 3
In recent years, these concepts have been
adapted to include formal risk - based inspection
procedures.
4
At the time of this writing, the American
Petroleum Institute (API) risk - based inspection stan-
dards have concentrated on downstream operations,
but they also have been applied to production and
pipeline operations for many years. The standard
has guidelines for pressure vessels, heat exchangers,
atmospheric storage tank shell courses and bottom
plates, compressors, pumps, and pressure relief devices.
All of this equipment is common to upstream as well
as downstream operations, and the standard is
divided into sections on inspection planning, deter-
mination of the probability of failure, and modeling
consequences.
5
Figure 7.1 shows a simple illustration of these ideas.
The horizontal piping shown in Figure 7.1 has three
areas of differing corrosion risks. Organizations are
likely to concentrate both inspection and monitoring
efforts in locations A and C of this structure because
they are the locations where corrosion and/or erosion
damage is more likely. Testing for the effectiveness of
corrosion inhibitors should also emphasize the fl ow con-
ditions in these areas, and it is likely that corrosion
control efforts effective in these high - susceptibility loca-
tions will also be effective in low - susceptibility areas
like location B in Figure 7.1 .
Identifi cation of these high - priority areas is the
reason why design, operations, and inspection person-
nel need to understand the different kinds of corrosion
and other degradation mechanisms likely to occur on
specifi c types of equipment.
186
Metallurgy and Corrosion Control in Oil and Gas Production,
by Robert Heidersbach
Copyright © 2011 John Wiley & Sons, Inc.
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INSPECTION, MONITORING, AND TESTING 187
mance. Optical aides such as pit gages, borescopes,
fi ber - optic cameras, and TV - camera remote - operated
underwater vehicles (ROVs) extend VI beyond loca-
tions where inspectors can have personal access.
7
Figure
7.2 shows a manual pit gage being used to measure the
depth of pitting on the exterior surface of a pipeline.
Surface cleaning, not necessary with some other
techniques, is very important for VI, especially when
checking for cracks, for example, from stress corrosion
or corrosion fatigue. Once marine growth was removed,
the pit shown in Figure 5.21 was visible. Fracture
mechanics analysis then determined that underwater
welding was necessary to prevent this pit from becom-
ing a dangerous stress riser that could lead to corrosion
fatigue of the platform node.
8
The primary advantage of VI is the curiosity and
integrity of the individual inspector. While checklists
and preplanned inspection procedures are important,
this technique, more than others, allows the inspector
to observe unanticipated phenomena. This is the reason
why all inspectors need some training in all forms of
degradation, mechanical and corrosion - related, that
they are likely to encounter. Visual inspectors can also
identify situations where other inspection techniques
are appropriate.
Recent experience with pipeline corrosion has led to
increased emphasis on VI, and external corrosion direct
assessment and internal corrosion direct assessment
techniques (including VI) have received increased
emphasis in recent years.
9 – 12
Benefi ts of VI :
4,7
•
Large areas are quickly scanned
•
Pit depths and pitting rates can be identifi ed
INSPECTION
Inspections can be planned and scheduled or occur
during unplanned shutdowns, construction modifi ca-
tions, and so on. The primary purpose of inspections is
to assess the fi tness for intended service of the equip-
ment in question. Most inspections are intended to be
nondestructive, and industry tends to use the terms
nondestructive testing (NDT), nondestructive inspec-
tion (NDI), and nondestructive evaluation (NDE)
interchangeably.
4
Fabrication - related NDT tends to emphasize welding,
locations where manufacturing defects are more likely
to occur, and in - service inspections also concentrate on
welds, which tend to be locations more likely to be
associated with structural failure, and on corrosion.
Choosing where to inspect depends on an under-
standing of the structural loading of the equipment con-
cerned as well as the fl ow patterns of any fl uids involved
and any other parameters likely to affect long - term
equipment reliability and corrosion degradation.
Risk - based inspection procedures are intended to
concentrate efforts on high - risk, high - consequence
(e.g., safety or expense) failure locations within in a
system. Projected results of using risk - based inspection
priorities are likely to result in increased inspection
intervals for most inspection locations and some high -
consequence locations where increased inspection fre-
quency will be indicated. The purpose of these
procedures is to move from mandated or calendar -
based inspection to inspections based on logic, data, and
documented experience.
5
The following discussion covers some of the NDT
inspection methods most likely to be used in upstream
oilfi eld operations.
Visual Inspection ( VI )
The most common form of inspection is VI to identify
surface abnormalities that can affect system perfor-
Figure 7.1 Areas of increased corrosion susceptibility in a
horizontal piping system.
6
A
B
C
Direction
of flow
* Limiting velocity—velocity above which erosion damage can be
expected.
A. Water oscillates—corrosion accelerated
B. Corrosion not accelerated
C. Water impinges at C—corrosion accelerated with higher
flow rate (above limiting velocity).*
Figure 7.2 The use of a manual pit gage to measure the
depth of external pitting on a pipeline.
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188 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION
Penetrants come in two basic types, fl uorescent and
visible penetrants, and are selected based on pene-
trating capability and contrast of the dyes. Fluorescent
penetrants are primarily used in construction and manu-
facturing, and require the surfaces being inspected to
be visually inspected using ultraviolet light. It is common
for fi eld inspectors to have portable aerosol cans of dye
penetrant, cleaner/remover, and developer.
Benefi ts of PT :
4,7,13
•
Simple and rapid
•
Makes surface defects easier to be seen
•
Works on all nonporous materials
Limitations of PT :
4,7,13
•
Requires skilled inspectors
•
Limited to surface defects
•
Requires direct access to the surface being
inspected
•
Chemical cleaning and disposal is necessary
•
Paint or coatings may mask defects
Magnetic Particle Inspection ( MT )
MT serves most of the same purposes as dye PT, but it
is considered to have two advantages. It can detect near -
surface fl aws (e.g., hydrogen blisters or weld defects)
that would be missed by surface - specifi c inspection
methods such as visual or dye penetrant inspection. For
magnetic materials, it can sometimes detect smaller
defects that would not be detected by penetrant inspec-
tion. It is used for detecting cracks and similar defects
on welds, drill tools, pipelines, and any other iron - based
or ferromagnetic components.
The process involves applying a magnetic fi eld, either
with permanent magnets or with an AC coil, to the area
to be inspected. Then, a suspension of iron particles is
sprayed onto the surface and the residual magnetic
fi elds “ decorate ” surface or near - surface fl aws — defects
that interrupt the magnetic fi eld in the magnetized part
being inspected. It is common to apply these particles
over a contrast - enhancing temporary coating and to use
colored particles to enhance visibility. MT usually
involves dry powder application of magnetic powders
and visible light inspection, but wet sprays and ultravio-
let light inspection is also possible.
4
MT can even be
performed underwater to inspect subsea pipelines.
1
Figure 7.4 shows magnetic particle stress corrosion
cracking indications on the exterior of an in - service
crude oil pipeline.
•
Video techniques can be used if personnel access
is denied
•
Does not require extensive training or equipment
Limitations of VI :
4,7
•
Internal inspection usually requires shutdown
•
Borescopes and cameras only work during opera-
tion if medium is transparent
•
Limited to surface defects
Penetrant Testing ( PT )
PT, often called dye PT, can be applied to virtually any
nonporous surface and is a common method of inspect-
ing for cracks of all types. The procedure is fairly simple
and inexpensive:
•
The surface is cleaned.
•
A high - surface - wetting liquid with a colored dye is
applied to the surface and is allowed to seep into
defects through capillary action.
•
Excess penetrant is removed from the surface.
•
A powdered developer is applied to pull the
trapped penetrant from the defect and spread it on
the surface so it can be seen.
•
VI then determines the location of the defects.
Figure 7.3 shows dye penetrant indications of stress
corrosion cracking on a stainless steel component.
Figure 7.3 Dye penetrant indications of stress corrosion
cracking on a stainless steel component.
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