Corrosion—The Longest War
Locations that host oil and gas operations often provide ideal conditions for corrosion.
Ongoing research and advances in coatings, cathodic protection, nondestructive
testing, corrosion analysis and inhibitors allow operators to safely produce oil and
gas in these corrosive environments.
Nausha Asrar
Bruce MacKay
Sugar Land, Texas, USA
Øystein Birketveit
Marko Stipaničev
Bergen, Norway
Joshua E. Jackson
G2MT Laboratories, LLC
Houston, Texas
Corrosion validates the universal law of entropy;
everything trends toward a state of greater chaos
and disorder. The flecks of rust on an iron bar or
the green patina on a copper fixture are evidence of
the insidious effects of corrosion. These examples
may be regarded as an annoyance, but taken to the
extreme, the results of corrosion can lead to catastrophic outcomes.
Corrosion has brought down bridges, downed
aircraft, leveled chemical plants, parted drillpipe and ruptured pipelines. Given sufficient
time, this adversary has the potential to degrade
any material. In certain environments, the
unchecked effects of corrosion can come swiftly,
and the consequences of failure to manage corrosion can be costly.
Alyn Jenkins
Aberdeen, Scotland
Denis Mélot
Total
Paris, France
Jan Scheie
Stavanger, Norway
Jean Vittonato
Total
Pau, France
Oilfield Review 28, no. 2 (May 2016).
Copyright © 2016 Schlumberger.
DS-1617 is mark of M-I LLC.
Hastelloy is a registered trademark of
Haynes International, Inc.
Inconel and Monel are trademarks of
Special Metals Corporation.
34
Oilfield Review
According to the US Federal Highway Administration, the approximate annual direct cost of
corrosion for the US in 2015 was an estimated
US$ 500 billion, representing around 3.1% of
the nation’s gross domestic product.1 This figure
amounts to six times the average annual cost of
weather-related disasters for the US, which was
about US$ 87 billion in 2011.2 Unlike weather
events, corrosion can be controlled or at least
managed; scientists estimate that 25% to 30% of
corrosion costs could be avoided if good corrosion
management practices and preventive strategies
were employed.3
Throughout the ages, and despite an early
lack of understanding concerning the fundamental mechanisms involved, humans have attempted
to control corrosion. In ancient times, corrosion
resistance was sometimes imparted to materials
as a matter of circumstance rather than design
(Figure 1).4 Early corrosion control methods
included the use of bitumen and lead-based
paints by the Romans in the first century. Around
500 BCE, Chinese sword makers used copper
sulfide coatings to inhibit corrosion on bronze
swords. Centuries later, the copper sheathing
used on British sailing vessels to reduce biofouling—fouling of underwater surfaces by organisms
such as barnacles and algae—and increase speed
accelerated the corrosion of nails that held the
ships together.5
1. Koch GH, Brongers MPH, Thompson NG, Virmani YP and
Payer JH: “Corrosion Costs and Preventive Strategies in
the United States,” Washington, DC: US Department of
Transportation Federal Highway Administration,
Publication FHWA-RD-01-156, March 2002.
Jackson JE: “Corrosion Will Cost the US Economy over
$1 Trillion in 2015,” G2MT Laboratories, http://
www.g2mtlabs.com/corrosion/cost-of-corrosion/
(accessed January 6, 2016).
Papavinasam S: Corrosion Control in the Oil and Gas
Industry. Waltham, Massachusetts, USA: Gulf
Professional Publishing, 2014.
2. The US$ 87 billion cost of weather-related disasters in
2011 was the highest on record. The average annual cost
has been closer to US$ 10 billion in recent years. For
more on the cost of weather-related disasters: Smith AB
and Katz RW: “U.S. Billion-Dollar Weather and Climate
Disasters: Data Sources, Trends, Accuracy and Biases,”
Natural Hazards 67, no. 2 (June 2013): 387–410.
3. Chillingar GV, Mourhatch R and Al-Qahtani GD: The
Fundamentals of Corrosion and Scaling for Petroleum
and Environmental Engineers. Houston: Gulf Publishing
Company, 2008.
4. Kumar AVR and Balasubramaniam R: “Corrosion Product
Analysis of Corrosion Resistant Ancient Indian Iron,”
Corrosion Science 40, no. 7 (July 1, 1998): 1169–1178.
Balasubramaniam R: Story of the Delhi Iron Pillar. Delhi,
India: Foundation Books Pvt. Ltd, Cambridge House, 2005.
5. Groysman A: Corrosion for Everybody. Dordrecht, The
Netherlands: Springer Science+Business Media, 2010.
6. Ahmad Z: Principles of Corrosion Engineering and
Control, 1st ed. Burlington, Massachusetts: ButterworthHeinemann, 2006.
7. Kermani MB and Harrop D: “The Impact of Corrosion on
the Oil and Gas Industry,” SPE Production & Facilities 11,
no. 3 (August 1996).
May 2016
PA
S
KI
TA
N
C H I N A
NEP
AL
New Delhi
BANGLADESH
I
N
D
I
A
Mumbai
0
0
km
500
miles
SRI LANKA
500
Figure 1. Delhi pillar. This iron pillar is located in the Qutub Complex in New Delhi, Delhi, India (inset).
It is about 9.1 m [30 ft] tall and weighs approximately 6,000 kg [13,200 lbm]. Erected in 400 CE, the
pillar is essentially free of the typical rusting that would be expected to take place over 1,600 years
of exposure. Reasons for the lack of corrosion include New Delhi’s low humidity but are primarily
attributed to the high concentration of phosphorus in the iron.
Michael Faraday was one of the most important contributors to the early understanding of
corrosion; in the early 1800s, he established a
quantitative relationship between the chemical action of corrosion and electric current.6
Although much more is known about the subject
today, scientists continue to study the mecha-
nisms of corrosion and search for methods to
manage and control it.
Combating corrosion is a significant source
of expenditures for the oil and gas industry
(Figure 2). British Petroleum (BP) conducted a
study of its operations in the North Sea in 1995.7
The company found that outlays for corrosion
US Oil and Gas Corrosion Expenditures, US$ billion/year
Oilfield Review
MAY 16
Refining
Corrosion
Fig 1 Distribution
3.7
ORMAY 16 CRSSN 1 5.0
Production
1.4
Storage
7.0
Tankers
2.7
Pipelines
7.0
Figure 2. Corrosion expenditures. Corrosion expenditures in the US
oil and gas industry are about US$ 26.8 billion/year. The downstream
segment of the industry—production, pipelines and tankers—
accounts for 41% of the total, or US$ 11 billion/year. (Adapted from
Koch et al, reference 1.)
35
Anodic reaction
Fe0 Fe2+ + 2e –
Cathodic reaction
H2O + 2e – 0.5 O2 + 2OH –
Fe2+ + 2OH – Fe(OH) 2
OH –
OH –
Water
OH –
Fe 2+
Fe0
Fe(OH) 2
Anode
Fe(OH) 2
Fe 0
Cathode
Electron flow
Fe0
Fe 0
Steel
Figure 3. Corrosion cell. When steel in water rusts, several reactions take
place simultaneously. At the anode, steel [Fe0] goes readily into solution to
form ferrous iron [Fe2+] and ferric iron [Fe3+] (not shown) ions, and electrons
move to the cathode. Electrons at the cathode react with water [H2O] to
form oxygen [O2] and hydroxyl [OH–] ions. The OH– ions combine with the
solubilized Fe2+ to form iron hydroxide [Fe(OH)2].
prevention and control averaged about 8% of
Some forms of metal corrosion are related
the total capital expenditure for its projects. to stability; for example, galvanic corrosion is
On the UK Continental Shelf, 25% to 30% of BP’s an electrochemical process associated with the
operating costs were related to the control and movement of electrons between areas that have
management of corrosion. Costs associated with different electrochemical potentials. The corroreplacing corroded equipment, lost production sion cell schematically describes oxidizing corroand corrosion-related contamination contributed sion, which is analogous to a battery in which two
to overall expenditures. In addition to the direct dissimilar metals are connected by an electrolyte
costs, the company found that corrosion had a (Figure 3).9 A metal that has a higher corrosion
significant indirect cost on health, safety and rate—more unstable—represents the negative
environmental concerns.
part of the cell and acts as the anode; a second
This article focuses on descriptions of cor- metal that has a lower corrosion rate—more
rosion, management techniques and advances stable—acts as the positive part of the cell,
in corrosion abatement technologies. Field the cathode.10
examples from Gabon, deepwater Nigeria
andReviewDuring the galvanic corrosion process, metal
Oilfield
the North Sea illustrate the ongoing battle
waged
MAY 16 oxides are formed as electrons flow from the
Corrosion Fig
3 to the cathode through the electrolyte—
against corrosion by oil and gas operators.
anode
ORMAY 16 the
CRSSN
fluid3in contact with the anode and cathode.
The Corrosion Process
A simplified version of iron oxidation can be used
Scientists and engineers today have a better to illustrate the galvanic corrosion process—the
understanding of corrosion processes than did actual process is more complex. The presence of
the ancient Romans and Chinese. Fighting cor- water [H2O] on the surface of the iron [Fe or Fe0]
rosion requires an understanding of the principal releases electrons to form ferrous iron [Fe+2] and
elements that cause and contribute to the corro- ferric iron [Fe+3] ions, which act as the anode in
sion. There are several categories of corrosion; for our battery analogy. The liberated electrons flow
the oil and gas industry, common types include to the cathode, where, in the presence of oxygen
exposure to carbon dioxide [CO2, sweet corro- [O2], ferrous oxide [FeO] and ferric oxide [Fe2O3]
sion], hydrogen sulfide [H2S, sour corrosion], form as scales of rust or precipitates. A byproduct
oxygen [O2] and corrosion causing microbes, of the reaction at the cathode is hydroxyl ions
referred to as microbiologically influenced cor- [OH–] from the reduction of oxygenated water.
rosion (MIC).8
36
Iron can also react with CO2 to form iron carbonate [FeCO3] and with H2S to form iron sulfides
[FexSx]. In the absence of O2 but the presence of
CO2 and H2S, the cathodic reaction can generate
hydrogen gas.
These reactions can occur rapidly, but if the
reaction rate can be reduced, the overall corrosion rate will also be reduced. Many factors influence the reaction rate. These include the type
and quality of metal, electrolyte compositions,
pH, temperature, pressure, presence of dissolved
gases, liquid velocity, water salinity, application of cathodic protection and the presence of
microbes.11 To manage corrosion and corrosion
rate, knowledge of the metallurgy of the materials to be used and the environments in which
they will operate is important.
If CO2 comes into contact with water in the
producing or transportation system of an oil and
gas operation, areas typically affected include
well internals, gathering lines and pipelines. In
CO2 corrosion of iron, the products of reaction
are carbonic acid, iron carbonate [FeCO3] and
hydrogen gas [H2].12 For CO2 corrosion to occur,
the partial pressure of the gas can be as low as
21 kPa [3 psi]. To prevent this type of corrosion,
operators commonly use organic films that act as
barriers and inhibitors that neutralize the acidity
of the carbonic acid generated in the corrosion
process. Operators may also use corrosion resistant alloys (CRAs), which are resistant to general
and localized corrosion, in environments that are
corrosive to carbon and low-alloy steels.
Hydrogen sulfide is often found in produced
fluids or as a result of MIC.13 Although H2S is not
corrosive, it becomes corrosive in the presence
of water.14 Sour corrosion from H2S can affect
any part of the producing system, including well
internals and oil and gas gathering lines. Oilfield
fluids are considered sour if the produced gas contains more than 5.7 mg of H2S per m3 [4 parts per
million (ppm)] of natural gas or produced water
has greater than 5 ppm H2S.15 At the anode, the
H2S reacts with the iron to form several variants of iron sulfide [FexS] such as mackinawite
[(Fe,Ni)(1 + x)S], pyrrhotite [Fe(1 - x)S] and troilite
[FeS].16 These iron sulfide species precipitate and
can form localized microgalvanic corrosion cells.
The corrosion cells formed during sour corrosion cause pitting, sulfide stress cracking (SSC)
and hydrogen embrittlement.17 Stress corrosion
cracking is a result of tensile stress combined
with a wet environment and often causes shallow, round pits that have etched bottoms accompanied by branching cracks that can lead to rapid
failure. Hydrogen embrittlement occurs when
H2S and H2 diffuse into metal, recombine with
Oilfield Review
Corrosion Form and Appearance
The word corrode comes from the Latin corrodere
meaning to gnaw; it can carry the additional
meaning of eat or wear away gradually.21
Corrosion typically leaves a visible signature that
is characteristic of the agent and mechanism
May 2016
30
25
Corrosion rate of carbon steel, mpy
other molecules and create pressure within the
metal matrix; byproducts of cathodic protection,
galvanic corrosion and other mechanisms may
lead to hydrogen embrittlement.
The failure mode during hydrogen embrittlement depends on the steel type; for example,
low-strength steels exhibit blistering. The failure
mode of high-strength steels can be catastrophic
when the pressure of the trapped gas exceeds the
tensile strength of the metal. To control sour corrosion, operators use organic film formers, H2S
scavengers, metals resistant to SSC, flowline pigging, nitrate treatments and biocides that reduce
the growth of microbes that cause MIC.18
Oxygen-related corrosion in oil and gas
producing environments is often much more
aggressive than corrosion caused by CO2 or H2S
(Figure 4).19 Corrosion by oxygen is directly proportional to the concentration of the dissolved
gas. If chlorides, CO2 or H2S are present, the corrosion rate can increase significantly.
Oxygen has the ability to induce corrosion
throughout producing systems. Inhibition of oxygen corrosion is difficult, and corrosion reduction
efforts for production and water handling facilities have usually been directed toward exclusion
of oxygen from the system and the use of oxygen scavengers. Typical oxygen scavengers are
ammonium bisulfite [NH4HSO3], sodium sulfite
[Na2SO3] and sodium bisulfite [NaHSO3].20 In
addition to scavenger stripping, vacuum deaerators are sometimes used to control the corrosive
effects of oxygen on metals.
Exposure to oxygen is also a major source of
drillpipe corrosion. While it is being run in and
out of the well, drillpipe is exposed to atmospheric oxygen. During drilling, drillpipe comes
into contact with oxygen in the mud system.
Both instances can induce corrosion. The usual
expression of oxygen-related corrosion is pitting.
Pitting can even develop under mud left on and
inside drillpipe, where pipe storage racks contact
the pipe and at crevices. Deep corrosion pits in
drillpipe can lead to the onset of fatigue failure.
Drillpipe may be coated with epoxies or resins
to stop corrosion, but the harsh downhole environment often quickly removes these protective
coatings. Pipe dope, lubricating grease applied
to threaded connections, may help prevent corrosion of these connections.
20
15
O2
CO2
10
H2S
5
0
1
2
3
4
50
100
150
200
100
200
300
400
5
6
7
8
250
300
350
400
450
500
600
700
800
900
Oxygen
Carbon dioxide
Hydrogen sulfide
Gas concentration in water phase, parts per million
9
Figure 4. Corrosion rates. The relative rates of corrosion in milli-inches/year (mpy) of carbon steel
show pronounced differences when the steel is exposed to varying concentrations of O2, CO2 and H2S.
At a concentration of 5 ppm, O2 is almost three times more corrosive than is H2S and 30% more
corrosive than is CO2. Photographs near each curve show the effects of these corrosion agents on
metal surfaces.
15.Stewart M and Arnold K: Gas Sweetening and
  8.Popoola LT, Grema AS, Latinwo GK, Gutti B and
Processing Field Manual. Waltham, Massachusetts.
Balogun AS: “Corrosion Problems During Oil and Gas
Gulf Professional Publishing, 2011.
Production and Its Mitigation,” International Journal of
Industrial Chemistry 4, no. 1 (2013).
16.Ning J, Zheng Y, Young D, Brown B and Nesic S:
“A Thermodynamic Study of Hydrogen Sulfide Corrosion
Chillingar et al, reference 3.
of Mild Steel,” paper NACE 2462, presented at the
  9.Stansbury EE and Buchanan RA: Fundamentals of
NACE Corrosion 2013 Conference and Exhibition,
Electrochemical Corrosion. Materials Park, Ohio, USA:
Orlando, Florida, USA, March 17–21, 2013.
ASM International, 2000.
17.Kvarekval J: “Morphology of Localized Corrosion Attacks
Brondel D, Edwards R, Hayman A, Hill D, Mehta S
in Sour Environments,” paper NACE 07659, presented at
and Semerad T: “Corrosion in the Oil Industry,”
the NACE Corrosion 2007 Conference and Exposition,
Oilfield Review 6, no. 2 (April 1994): 4–18.
Nashville, Tennessee, USA, March 11–15, 2007.
10.Although the battery analogy is acceptable for
18.Pipeline operators send mechanical devices called pigs
explaining corrosion involving two dissimilar metals,
Oilfield
corrosion processes also take place on single
metals. Review through pipelines to clean the inner surface. This can be
done without halting flow, and the flow stream pushes
16
In single metals, the mechanism for corrosionMAY
consists
of small crystals with slightly different compositions.
Corrosion Fig 4 the pig through the piping.
19.Popoola et al, reference 8.
The anode and the cathode are located on different
ORMAY 16 CRSSN
4
areas of the metal surface and, depending on the
Chillingar et al, reference 3.
conditions, may be close to each other or far apart.
20.Chillingar et al, reference 3.
11.Heidersbach R: Metallurgy and Corrosion Control in
Care must be taken when using NH4HSO3 as an oxygen
Oil and Gas Production. Hoboken, New Jersey, USA:
scavenger. This compound is corrosive in itself and can
John Wiley & Sons, Inc., 2011.
also act as a food source for bacteria, thereby
12.At elevated temperatures, magnetite [Fe3O4] may
potentially encouraging MIC.
also form.
21.Davis JR: Corrosion—Understanding the Basics.
13.In MIC, the H2S is produced as a byproduct of the
Materials Park, Ohio: ASM International, 2000.
activities of sulfate reducing bacteria (SRB).
14.Chillingar et al, reference 3.
37
Water
Flow
Anode
Cathode
Steel
General or Uniform
Galvanic
Erosion or Flow Induced
Crevice
Water
Steel
Force
Pitting
Intergranular
Stress
Corrosion Cracking
Corrosion Fatigue
Figure 5. Generalized categories of corrosion. Corrosion can be categorized by appearance and the
agent of causation. These eight corrosion types cover most of the observed corrosion mechanisms
for metals.
that caused it. Although not an exclusive list, corrosion usually falls into one or more of the following categories: general or uniform, localized,
galvanic, erosion or flow induced, crevice, pitting,
under deposit, cavitation, intergranular, stress
cracking and corrosion fatigue (Figure 5). Other
types of corrosion include environmental, top-ofline and microbial. Based on the observed characteristics of the corrosion, engineers can adopt
appropriate preventive and mitigation measures.
Uniform corrosion is typical of low-alloy
steels and may be observed over an entire
exposed area. Initial evidence of uniform corrosion is surface roughness. The metal becomes
thinner as the corrosion progresses, and it will
eventually fail from internal pressure or external
forces. Because this type of corrosion is linked to
surface exposure, it may be prevented by properly protecting the surface. Uniform corrosion
may occur in equipment used for oilfield operations such as hydraulic stimulation and acidizing.
Localized corrosion occurs at specific sites
rather than over a generalized area and may be
more dangerous than some other types of corrosion because of its unpredictable nature and
38
the potential for rapid growth. Localized corrosion, of which even CRAs such as stainless steels
are susceptible, can be subdivided into pitting,
crevice and under deposit corrosion. Pitting ultimately can cause holes in metal components and
is one of the primary causes of failure in oilfield
hardware, including tubing, casing, sucker rods
and surface equipment.
Crevice corrosion occurs in constricted areas,
wherein the metal at the crevice becomes anodic
and the rest of the metal serves as the cathode.
The crevice can form where two dissimilar metals
come into contact or be created by microgalvanic
cells that may occur in certain steel alloys.
Pitting corrosion rates are often much higher
than those of other types of corrosion. Inhibitors
Oilfield
may be applied
to theReview
surface to prevent initiaMAY 16
tion, but once Corrosion
a pit has formed
Fig 5 the inhibitors are
often unable toORMAY
slow its16
growth.
CRSSN 5
Under deposit corrosion occurs when sand,
corrosives or porous solids adhere to the metal
surface. Although the area underneath the
deposit is resistant to inhibitors and can corrode
quickly, this type of corrosion can often be man-
aged by cleaning internal piping surfaces, for
example, with the use of pipeline pigs.
Galvanic corrosion can be a problem when
two dissimilar metals are in contact. The metal
that has the least resistance to corrosion acts as
the anode and the more resistant metal serves as
the cathode. The anode typically corrodes preferentially. This form of corrosion is frequently
observed in offshore platforms and pipelines.
The galvanic series, which orders metals according to their anodic or cathodic tendencies, is a
good predictor of corrosion severity (Figure 6).
Galvanic corrosion is controlled and mitigated by
use of the following:
•good engineering design—to ensure that corrosively active components present larger surface area than do less active components
•material selection—to avoid metals far apart
in the galvanic series
•isolation—to provide pipelines coming from the
sea with sacrificial anodes and protect those
going into land with impressed current systems
•inhibitors and coatings—to control initiation
of corrosion, although this method may be ineffective once corrosion forms.
Oilfield Review
Flow-induced corrosion occurs when liquid
flow accelerates corrosion. Wellheads and pumps
are susceptible to this form of corrosion, which
may occur as erosion or cavitation. Erosion corrosion results when fluid flow removes the protective film that forms naturally or has been
applied externally. Because of their abrasive
properties, suspended solids will accelerate the
process. Damage can be seen as grooves in the
piping that correspond to the flow direction.
Proper engineering design that allows for sufficient pipe diameter and removing solids from
flow streams can minimize this type of corrosion.
Inhibitors may be applied to replace protective
films stripped away by the flowing fluids.
Pipe
Wet gas
Condensate
Monoethylene glycol
Anodic
Magnesium
Zinc
Cadmium
Aluminum
Steel
Chromium steel
Stainless steel
Lead
Figure 7. Top-of-line pipeline corrosion. Top-of-line corrosion can
result from the stratified multiphase flow of wet gas in horizontal
pipelines. Liquids—including condensate and inhibitors such as
monoethylene glycol—settle to the bottom of the pipe. Wet gas fills
the pipe above the liquid line. If either CO2 or H2S are present in the
gas, along with water, corrosive byproducts form at the top of the
pipe and may not be controlled if the inhibitor remains at the bottom
of the pipe.
Tin
Nickel
Inconel
Hastelloy
Brasses
Copper
Bronzes
Monel
Chromium steel
Silver
Titanium
Graphite
Gold
Platinum
Cathodic
Figure 6. Galvanic series. Metals (not all shown)
can be described by their anodic or cathodic
tendencies arranged in a galvanic series. When
dissimilar metals are connected electrically
and submerged in an electrolyte, the anodic
metal, rather than the cathodic metal, will
preferentially corrode. The rate of corrosion is
a function of the separation between the paired
metals in the galvanic series. The series shown
here is for seawater; the order may change
based on the electrolyte.
May 2016
Oilfield Review
MAY 16
Corrosion Fig 6
Cavitation is caused by collapsing bubbles •hydrogen embrittlement—hydrogen enters
that occur when the pressure changes rapidly in
the metal matrix and weakens it
flowing liquids. Over time, cavitation may cause •stress corrosion cracking—cracks form after
deep pits to form in areas of turbulent flow, especorrosion has attacked a surface
cially in pump impellers. Low-carbon steels are •sulfide stress cracking—a failure of the metal
susceptible; stainless steels are more resilient.22
caused by H2S.
Material
selection—opting for materials that are
Intergranular corrosion results from corrosive attacks at metal grain boundaries in the resistant to hydrogen embrittlement and sulfide
form of cracks. The grain boundaries can become cracking—is the primary avoidance technique.
anodic with reference to the cathodic surround- Low-stress design practices and stress relief by
ing surface, typically due to formation of chro- heat treatment are also commonly used, and premium carbides or nitrides. Metal impurities can venting corrosion in components subject to stress
increase the effect, as can precipitates in the is another method.
Pipelines are subject to top-of-line corrosion
metal that form during heat treatments. When
Oilfield Review
(Figure
7). Water condenses at the top of the
chromium combines with nitrogen orMAY
carbon,
16
pipe
as
the
fluid inside cools. The corrosion rate
less free chrome is available locally for
corroCorrosion Fig 7
depends
on
sion protection, and cracks can form along
the
ORMAY 16 CRSSN 7 the condensation rate and concengrain boundaries. Quenching—the rapid cool- tration of organic acids. Generally, this type of
ing after heat treatments—may be effective in corrosion is controlled with inhibitors and pipereducing or eliminating intergranular corrosion. line insulation that reduces condensation.
Material selection—avoiding metals that are
22.Port RD: “Flow Accelerated Corrosion,” paper NACE 721,
susceptible to this condition—is the most relipresented at the NACE Corrosion 98 Annual Conference,
San Diego, California, USA, March 22–27, 1998.
able method to preclude intergranular corrosion.
International: “Standard Practices for Detecting
Tests such as ASTM A262 can be used to evaluate 23.ASTM
Susceptibility to Intergranular Attack in Austenitic
Stainless Steels,” West Conshohocken, Pennsylvania,
susceptibility of materials to this mechanism.23
USA: ASTM International A262-15, 2015.
Environmental cracking occurs when cor­
rosion coincides with tensile stress. It may be
manifested as the following:
39
Separator Tank
Sidestream
Emulsion
Water outlet
Oil outlet
Water
Oil layer
Corrosion
inhibitor film
Iron sulfide
particle
Figure 8. Microbiologically influenced corrosion products. Softscale
corrosion, referred to as schmoo (right), can form in production systems
if microbes are not controlled. The photograph shows a mixture of
iron sulfide [FeS], asphaltenes and biomass that was collected at the
sidestream outlet of a separator tank (top left). Corrosion inhibitors form
protective films around iron sulfide particles (bottom left) inside the
separator and prevent softscale formation in produced waters.
Microbiologically Influenced Corrosion
From the moment of immersion in a nonsterile fluid that supports microbial development,
microorganisms begin to attach to the material
surface (Figure 8). Planktonic microorganisms
become fixed at the fluid boundary, typically a
pipe wall, or onto porous media such as preexisting corrosion.24
Attachment of microorganisms leads to the
formation of biofilms—microbial communities
embedded in or on an attaching surface.25 Wherever biofilms are found in producing systems,
MIC can occur, including inside production tubing, gravity and hydrocyclone separators, storage
tanks, pipelines and water injection systems.
Depending on the microbial species, the corrosion mechanisms can take various forms.
Biofilms can trap ions and create localized
electrochemical potentials analogous to a galvanic corrosion cell or may contribute to corro-
Oilfield Review
MAY 16
Corrosion Fig 9
ORMAY 16 CRSSN 9
Figure 9. Microbiologically influenced corrosion from byproducts. Biofilm on
the surface of this metal piece produced H2S that damaged the piece and
led to premature failure of the equipment.
40
sion by taking a role in the formation of cathodic
and conductive corrosion products on the metal
surface (Figure 9). Sulfate producing prokaryotes
(SPPs) are the chief offenders. Prokaryotes are
microbes that have no cell nucleus or membranebound organelles. The most prominent group of
SPPs are sulfate reducing bacteria (SRB) and
sulfate reducing archaea (SRA). They contribute
to corrosion by various means, for example, by
taking a role in the formation of cathodic ferrous
sulfide corrosion products and the formation of
galvanic cells. The production of H2S by SPPs can
also lead to sour corrosion.
Biofilms may develop local concentration
cells that are created by oxygen depletion or may
attach to a metal surface. Microbes can contribute to corrosion by the direct effects of metabolic waste products such as organic acids that
are capable of altering the local pH and forming
pH cells. Some microbes are anaerobic and can
tolerate extremes of pressure, temperature, pH
and fluid salinity. These include methanogens—
microbes that produce methane as a metabolic
byproduct in anoxic conditions.
Regardless of the source of MIC, prevention
measures in most cases attack planktonic and
sessile populations.26 Methods include biocides
to kill the microorganisms, coatings to inhibit
biofilm formation, removal of nutrients from the
flow stream to control microbial populations and
mechanical removal of an established biomass
via pigging.
Corrosion Control Methods
Metallurgical solutions can be effective deterrents of corrosion, but their costs may be beyond
the economic limit of many oilfield projects.
Building every structure and tubular from iridium—the most corrosion resistant element—
might win the battle against corrosion, but incur
unsustainable expenses, and that would be
assuming a sufficient supply of iridium exists in
the world to attempt such a task. Aluminum is
a corrosion-resistant metal used in many oilfield
applications; however, it is unsuitable for highpressure and high-temperature operations. In
addition, although aluminum is considered corrosion resistant in seawater, the mechanism for
resistance relies on the formation of a thin film
of aluminum oxide on the surface of the metal. In
environments that have high levels of acidity (low
pH) or alkalinity (high pH), the aluminum oxide
can become unstable and thus nonprotective. In
many cases, steel alloys and CRAs are required to
meet both strength and cost requirements.
Oilfield Review
Although materials selection is a major part
of the corrosion control process, once the equipment is deployed, oilfield operations generally
follow three methodologies to battle corrosion.
Operators and service companies rely on surface
coatings to protect susceptible metals, cathodic
protection for active protection and inhibitors as
a low-cost treatment option.
Surface coatings provide chemical and
mechanical resistance. They may also offer thermal protection. For surface coatings to provide
maximum effectiveness, good adhesion to the
target surface is required. Coatings are available
in organic and inorganic types. Organic coatings
include epoxies, phenolic resins, polyurethanes,
polyethylenes and polyesters. Metals applied as
suspensions and electroplating are examples of
inorganic coatings; inorganic ceramics may also be
applied to protect surfaces. Although not normally
an advanced-technology solution, the cement
placed in the annulus between the wellbore casing
and the formation can act as an inorganic coating
that prevents corrosion.
Cathodic protection (CP) consists of two primary forms: passive and active (Figure 10). In
either form, it relies on a movement of electrons
(current) from an external anode to the equipment being protected, which acts as a cathode.
Both the cathode and anode must be in the same
electrolyte and electrically connected. The most
common uses of CP are protecting large structures, piping, casing and equipment exposed to
the elements. It may also be installed inside or
outside tanks and pressure vessels.
Operators often use sacrificial anodes with
CP to protect structures in areas where electrical
power sources are not readily available such as
in remote operations or on offshore structures. If
the structure can be made to serve as the cathode
in relation to an anode, the disposable sacrificial
anode will corrode while the cathode remains
unscathed. This type of CP has been referred to
as fighting corrosion with corrosion.27
The first use of CP is attributed to Sir
Humphry Davy, who described the process in a
series of articles to the Royal Society of London
in 1824.28 The technique was used in an attempt
to prevent the corrosion of nails used in wooden
oceangoing vessels. Accelerated corrosion of the
nails occurred when copper cladding—used to
prevent biofouling—was applied to the outside
of vessels. Davy found that sacrificial anodes
protected the iron nails. The actual processes
were not well understood at that time, but it is
recognized today that the contact of dissimilar
metals—the copper cladding and the iron of the
May 2016
Galvanic DC current
milliamp
Electrolyte
Cathode
Anode
Backfill
Figure 10. Cathodic protection circuit. Cathodic protection methods may
use naturally occurring galvanic current or employ a direct current (DC)
source (impressed current) when the electrolyte is resistive. The protected
element—a pipeline is shown—is the cathode. The sacrificial element,
located some distance from the cathode, serves as the anode. The DC
source may be batteries or solar panels in remote pipeline applications.
nails—led to the corrosion. Davy and his assisBecause the direct current (DC) is extertant carried out a number of experiments on cor- nally applied, this type of corrosion managerosion prevention techniques; that assistant was ment is referred to as impressed cathodic
Michael Faraday, who would later establish the protection. It is most frequently used for cases
relationship between the chemical action of cor- in which the electrolyte resistance is high, such
rosion and electric current.
as in soil or freshwater, and where a constant
In the oil field, CP was first applied to land24.Stipaničev M: “Improved Decision Support Within
based pipelines, and the first documented use
Biocorrosion Management for Oil and Gas Water
Injection Systems,” PhD thesis, Institut National
was by Robert J. Kuhn in 1928.29 He established
Polytechnique de Toulouse, France (2013).
a negative 850 mV potential between the steel 25.Madigan MT, Martinko JM, Bender KS, Buckley DH,
Stahl DA and Brock T: Brock Biology of Microorganisms,
pipe of a pipeline and a copper-sulfate electrode.
14th ed. San Francisco: Benjamin Cummings, 2014.
This example became the foundation of modern
Oilfield Review
26.Sessile refers to fixed or immobile organisms.
CP technology, although for many years the
effecMAY
16 27.Lehmann JA: “Cathodic Protection of Offshore
Structures,” paper OTC 1041, presented at the
tiveness was met with scientific skepticism.
Corrosion Fig 10
First Annual
ORMAY
10 Offshore Technology Conference, Houston,
Today, CP uses sacrificial elements
made 16 CRSSN
May 18–21, 1969.
from aluminum, zinc and magnesium to protect 28.Davy H: “On the Corrosion of Copper Sheeting by Sea
Water, and on Methods of Preventing This Effect; And
the steel of large structures and piping. These
on Their Application to Ships of War and Other Ships,”
dissimilar metals create the galvanic coupling
Philosophical Transactions of the Royal Society of
London 114 (January 1, 1824): 151–158.
that establishes a current path between the
Baeckmann W: “The History of Corrosion
anode and the cathode, and, over time, the 29.von
Protection,” in von Baeckmann W, Schwenk W and
Prinz W (eds): Handbook of Cathodic Corrosion
sacrificial anode rather than the protected
Protection—Theory and Practice of Electrochemical
structure experiences metal loss. Appropriate
Protection Processes, 3rd ed. Houston: Gulf Professional
Publishing (1997): 1–26.
placement and distribution of the anodes is crucial to ensure that all parts of the structure are 30.Amani M and Hjeij D: “A Comprehensive Review of
Corrosion and Its Inhibition in the Oil and Gas Industry,”
sufficiently protected.30
paper SPE 175337, presented at the SPE Kuwait Oil
and Gas Show and Conference, Mishref, Kuwait,
October 11–14, 2015.
41
Water
Water
Oil
Oil
CH 3
Alkyl
chain
CnH 2n
N+
Polar head
group
Metal surface
Figure 11. Film formers. Although they vary in composition and avenue of
protection, film formers create barriers between corrosive elements (water
and oil, top) and metal surfaces. Inhibitors may be adsorbed on the surface
(alkyl chains, middle) or form a strong bond by sharing charges with the
metal (polar head group, bottom). When molecules of the polar head group
of film formers attach to the surface of the metal, a portion of the molecule
extends into the fluid. This usually oil-soluble tail is hydrophobic, repelling
water away from the metal surface.
source of current is readily available. The use is to interrupt the electrochemical process by
of solar panels in remote locations has greatly which the corrosion cell forms between the metal
increased the potential applications of impressed and the liquids in and around the equipment.
Inhibitors can be a flexible and cost-effective
cathodic protection.
In the impressed CP technique, current of method of fighting corrosion, and the inhibiseveral amps from a low-voltage rectifier passes, tor application can be altered when conditions
or is impressed, from an inert anode (for exam- change. Although acquiring and delivering the
ple, graphite or iron) to the structure being pro- inhibitor incur an ongoing cost, the lower costs
tected, which acts as the cathode. The anode associated with using less corrosion resistant
is attached to the positive terminal of the DC low-carbon steels usually more than make up
source, and the cathode is attached to the nega- the difference.
Inhibitors fall into four main categories: scavtive terminal. The anode and cathode are often
some distance from each other, separated by engers, reactive agents, vapor phase and film
formers. Oxygen scavengers are frequently used
an electrolyte.
To counteract corrosion, sufficient current in operations in which oxygen poses a corrosive
density must be supplied to all parts of the pro- threat. These agents not only reduce oxidizing
tected structure and the current density must corrosion, but also control the growth of microbes
always exceed what would be the measured cor- that require oxygen to thrive. Examples of oxygen
scavengers used in the oil and gas industry are
rosion rate under the same conditions.Oilfield
If theReview
corrosion rate increases, the impressed MAY
current
16 sodium sulfite, sulfur dioxide, sodium bisulfite,
Corrosion
11 metabisulfite and ammonium bisulfite.
sodium
density must be increased.31 Although the
initial Fig
ORMAY
CRSSN 11 bisulfite and sodium bisulfite are
equipment cost may be higher for impressed
CP 16Ammonium
than it is for sacrificial protection, this technique commonly used in seawater injection systems. To
may be less expensive over the long term because speed reaction rates, a catalyst may be included
sacrificial anodes do not need to be replaced. in the chemical.
Hydrogen sulfide scavengers reduce the
Impressed CP also has the advantage of providing information to the operator about the extent level of H2S in the flow stream. Examples of H2S
of corrosion over time.
scavengers are amines, aldehydes and zinc carboxylates. Common forms of amines are monoCorrosion Inhibitors
ethanolamine (MEA) and monomethylamine
Another line of defense against corrosion is (MMA) triazine. In some situations, operators
inhibitors, of which there are a variety of types may be able to regenerate MEA and MMA for
and applications. The primary goal of inhibitors reinjection and reuse.
42
Reactive inhibition operates at the cathode
level for the corrosion cell. The cations of the
inhibitor react with the cathodic anions to form
insoluble films, which adhere to the surface
of the metals and prevent O2 from coming into
contact with the metal. These films also prevent
the evolution of H2, a byproduct of the corrosion
cell. Examples are forms of calcium carbonate,
magnesium carbonate and iron oxides. Reactive
inhibitors can also serve as poisons to the corrosion cell process by interfering with the formation of H2 and reducing the reaction rates at both
the cathode and anode.
Vapor phase inhibitors are primarily used for
combating CO2 corrosion. These inhibitors neutralize CO2 and block the formation of carbonic
acid [H2CO3]. They are transported via vapor
phase in wet gas lines. To protect against future
corrosion, they may also be used during hydrostatic testing of components with water, especially when the components are to be stored after
fitness testing. Examples of these types of inhibitors include morpholine and ethylenediamine.
Film Formers
Film formers are the most widely used corrosion
inhibitors in the oil and gas industry. They create a continuous layer between the metal and the
reactive fluids, thus reducing the attack of corrosive elements (Figure 11). They may also attach
to the surface of corroded metal, altering it and
reducing the corrosion rate. Although they are
effective in reducing CO2 and H2S corrosion, film
formers are not effective against O2 corrosion.
Film formers are available in oil-soluble,
water-soluble and oil soluble–water dispersible
forms. Oil-soluble inhibitors are used to treat oiland gas-producing wells. Water-soluble inhibitors are used in high water-cut flow streams,
including those found in producing wells, transmission lines and separators. Oil soluble–water
dispersible inhibitors are used in oil and gas
wells that are also producing water.
Film-forming inhibitors take various chemical
forms but are typically composed of long carbon
chains with nitrogen, phosphate esters or anhydrides. Inhibitors may adhere to or be adsorbed
on the metal surface, which prevents the corrosives from attacking the metal. The most effective film-forming inhibitors create a molecular
bond at the metal surface in a process of charge
sharing or charge transfer. For effective inhibition, the surface of the metal being protected
must be fully covered; injection of the proper
concentrations of the inhibitor are crucial. After
they interact with the corrosive elements, some
Oilfield Review
inhibitors are gradually removed from the metal
surface and must be continuously replenished
with new inhibitor.
In the petroleum industry, organic inhibitors
are frequently used because they can form protective layers even in the presence of hydrocarbons.
Amides and imidazolines are examples of organic
film-forming inhibitors that are effective over
a wide range of conditions, especially in sweet
(CO2) and sour (H2S) gas corrosion environments.
They can be water or oil soluble. Amines, which
are also organic inhibitors, are effective for sweet
and sour corrosion but may exhibit biologic toxicity and are thus not as environmentally friendly
as are amides.
Quaternary ammonium salt, or quaternary
amine, inhibitors are effective against sour corrosion.32 The corrosive element formed by sour gas
is iron sulfide on the metal surface. Quaternary
ammonium cations, or quats, are positively
charged, and when they are adsorbed on the
surface of the material to be protected, they disrupt the normal corrosion cell charge. However,
at least one study indicated that quaternary
ammonium inhibitors may actually increase the
corrosion rate of sweet corrosion in the presence
of brine.33 The biocide properties of quaternary
ammonium salts may also prevent MIC.
Many additional film formers are used in the
oil and gas industry, including phosphate esters,
ester quats, dimer and trimer acids and alkyl pyridine quaternary compounds. Most film-forming
applications include multiple inhibitors; laboratory testing is used to establish optimum concentrations, fluid tolerances, stability, effectiveness
and persistency of the film. Inhibitor selection
can be a complicated process and typically must
be adjusted over time to meet the demands of
changing fluid conditions.
Inhibitor Selection
Laboratory evaluation is the key to developing
an effective program in inhibitor selection for
corrosion control. Technicians begin the process
using fluid samples that replicate field conditions—actual produced fluids are best if available. Simulated and synthetic fluids are used
when produced fluids cannot be obtained. From
laboratory tests, corrosion rates can be measured and predictions can be made for largescale operations (Figure 12). Methods for testing corrosion inhibitors include the following
tests: wheel, kettle (also called linear polarization resistance (LPR) tests), rotating cylinder
May 2016
Use of corrosion
inhibitor recommended
Predict corrosion rate
from field data
Develop and execute
testing program
Rotating Cylinder
Electrode Test
Kettle Test
Autoclave Test
Recommend and
implement corrosion
inhibitor addition
Conduct field trial
Sidestream Test
Analyze field
trial results
Make final
recommendation
Figure 12. Laboratory testing of corrosion inhibitors. Operators usually
develop corrosion control plans and then test inhibitors using conditions
expected from the field. This flowchart follows a testing sequence. Three
common testing methods are the rotating cylinder electrode, kettle and
autoclave tests (middle). Even after laboratory testing, field trials should be
conducted to validate the effectiveness of the program. A sidestream test
(lower left ) acquires samples for analysis. If the proposed method provides
acceptable results, the method is adopted, although the corrosion inhibition
program must be reevaluated during the life of the well.
31.Schweitzer PA: Corrosion of Linings and Coatings:
Cathodic and Inhibitor Protection and Corrosion
Monitoring. Boca Raton, Florida: CRC Press, 2006.
32.Binks BP, Fletcher PDI, Hicks JT, Durnie WH and
Horsup DI: “Comparison of the Effects of Air, Carbon
Dioxide and Hydrogen Sulphide on CorrosionOilfield
of a Low
Carbon Steel under Water and Its Inhibition by a
Quaternary Ammonium Salt,” paper NACE 05307,
presented at the NACE Corrosion 2005 Conference and
Exhibition, Houston, April 3–7, 2005.
33.Binks et al, reference 32.
Review
MAY 16
Corrosion Fig 12
ORMAY 16 CRSSN 12
43
Rack
Metal coupon container
High-temperature autoclave
Pressure source
(hydraulic pump)
Figure 13. Autoclave corrosion testing. A high-temperature autoclave is
used to test the effectiveness of corrosion inhibitors on metal coupons
(inset). Hydrostatic pressure and temperature can be applied to simulate
downhole conditions.
Thermometer
Voltage potential, mV
Gas sparge
electrode, autoclave, jet impingement and flow
loop (Figure 13). The most common are the
wheel and kettle tests.34
The wheel test measures the loss of metal
during a specified period of exposure to corrosive liquids. Corrosives include produced fluids,
brines and refined oils. The test fixture includes
a rotating wheel inside a sealed box that keeps
the specimen, usually strips of metal or coupons,
in constant motion. Temperature can be maintained at a constant value or varied to simulate
field conditions. The samples are tested with and
without inhibitor and the results are compared.
The kettle test, or LPR test, measures corrosion rates electrochemically. Metal electrodes
are placed in the test vessel, which is heated
while the corrosive fluid is continously agitated.
Agitation attempts to replicate field conditions—
mild agitation is similar to flow of two distinct
sources, and high agitation replicates turbulent
fluid flow that has dispersed hydrocarbons. To
simulate the presence of gases, CO2 and H2S can
be bubbled through the liquid in the vessel in a
process referred to as sparging.35
To establish a control corrosion rate, the test
is run with the electrodes exposed to the fluids
in aqueous phase without an inhibitor and then
followed by a series of tests on solutions that have
increased inhibitor volumes. Linear polarization
is performed by controlling the voltage potential
and measuring the current then controlling the
Steel electrode
Heating mantel
Voltage
Corrosion rate
Current
Current, mA
Stir bar
Figure 14. Kettle test. To perform kettle tests, or linear polarization resistance
tests, technicians use a test fixture (left) and control the pressure and
temperature. They submerge electrodes inside the fixture into the fluids
expected downhole and then measure electrical properties of the
electrodes. The tests are performed by controlling the voltage potential
44
and measuring the current then controlling the current and measuring
the voltage. The electrolyte can be agitated using the stir bar. Gas can be
injected into the test fixture, a process referred to as sparging. From the
slope of the polarization resistance curve (right ), the corrosion rate can
be computed.
Oilfield Review
Cape Lopez
Cathodic protection station
Section 1
Section 2
Section 3
Tchéngue
Cathodic protection station
AT LA N T IC O CEAN
GABON
Batanga
Cathodic protection station
Cathodic protection stations
powered by two solar cells
Input temperature
~ 60˚ C
Rabi Field
Cathodic protection station
Figure 15. Corrosion in a pipeline from the Rabi field to Cape Lopez. A
three-section, 18-in. pipeline carries oil from the inland Rabi field in Gabon
to Cape Lopez on the coast. Cathodic protection stations are located along
the pipeline. Because the incoming oil is hot (around 60°C), Section 1 of the
pipeline (red and dark blue) is exposed to a higher temperature than is the
remainder of the pipeline. The elevated temperature led to the disbondment
current and measuring the voltage potential.
The data are plotted, and the slope of the line
is the polarization resistance, which is inversely
proportional to the corrosion rate (Figure 14).
This technique provides corrosion rate evaluation from external measurements, whereas other
methods require technicians to physically measure and evaluate corrosion.
The effectiveness of inhibitors is dependent
on fluid velocity. For fluids containing little or
no solid particles, high flow rates can lead to
flow-accelerated corrosion. If the flow stream
contains solid particles, the accelerated corrosion is termed erosion corrosion. Several test
methods have been developed to model corrosion
in high-flow conditions and determine a film’s
persistence, especially where turbulent flow is
present.36 Test methods include jet impingement,
rotating cylinder electrodes and flow loop testing.
The testing of inhibitors should determine
the following:
May 2016
of the protective outer covering of the pipeline. Engineers concluded
that corrosion observed in Section 1 resulted from a combination of the
disbonding of the protective covering and ineffective cathodic protection.
Although the pipeline’s safety was not compromised, the operator
implemented new procedures to prevent the corrosion from recurring.
•thermal stability
•emulsification tendency
•foaming tendency
•metal compatibility
•elastomer compatibility
•compatibility with other chemicals used in the
same stream.
Application methods should be evaluated as well.
Injection may be continuous, batch or squeeze.
The rate of film removal is a key concern when
determining the optimal application mode.
Corrosion in the Oil Field
A recent example of pipeline corrosion from
Gabon illustrates the need for thorough testing
and understanding of the corrosion process.37 A
pipeline transports oil from the Rabi field to Cape
Lopez—a distance of approximately 234 km
[145 mi]. The 18-in. pipeline comprises three
sections: Section 1 from Rabi to Batanga, 105 km
[65 mi]; Section 2 from Batanga to Tchengué,
100 km [62 mi] and then Section 3 from Tchengué
to Cape Lopez, 29 km [18 mi] (Figure 15).
The inlet pressure at Rabi was about 40 bar
[580 psi], and the flowing temperature was 60°C
[140°F] at the inlet. Beyond the inlet, the line operates at about 35°C [95°F]. Impressed cathodic protection is used for the pipeline, which has sections
that have solar cells to provide current. The pipeline
was coated with three-layer polyethylene; each joint
was brush cleaned and wrapped with heat-shrink
34.NACE Task Group T-1D-34 on Laboratory Corrosion
Inhibitor Test Parameters: “Laboratory Test Methods for
Evaluating Oilfield Corrosion Inhibitors,” Houston, NACE
International, NACE Publication 1D196, December 1996.
35.NACE Task Group T-1D-34 on Laboratory Corrosion
Inhibitor Test Parameters, reference 34.
36.Efird KD: “Jet Impingement Testing for Flow Accelerated
Corrosion,” paper NACE 00052, presented at NACE
Corrosion 2000 Conference and Exhibition, Orlando,
Florida, March 26–31, 2000.
37.Melot D, Paugam G and Roche M: “Disbondments of
Pipeline Coatings and Their Effects on Corrosion Risks,”
Journal of Protective Coatings and Linings 26, no. 9
(September 2009): 67–76.
45
may have prevented cathodic current from reaching
and protecting the surface of the exposed steel.
Although engineers discovered corrosion as a result
of disbonding of coatings, based on ASME standards,
the degree of corrosion was deemed not mechanically dangerous. They also concluded that as long as
coatings remain bonded to the steel and cathodic
protection is correctly applied, monitored and maintained, no corrosion risk existed for this pipeline.
Figure 16. An example of pipeline corrosion. After the protective coating
disbonded on a pipeline in Gabon, corrosion formed as pitting (inset).
sleeves and hot-melt adhesive that overlapped the
polyethylene.38 The pipe was buried in wet, compacted sand that had a pH of approximately 5.4.
Problems began to develop in the first 15 km
[9.3 mi] of pipe. Routine inspections found disbondment at the sleeves where they overlapped
the polyethylene coating in the Rabi section.
Disbondment allowed water under the protective
coating, which negated the cathodic protection
and allowed corrosion to develop (Figure 16).
The remainder of the pipeline did not experience
the same level of corrosion, although significant
BURKINA FASO
BENIN
disbondment occurred in the sleeves. The main
difference between the sections that had differing corrosion levels was that the temperature in
the more corroded sections was higher. Further
testing of pipe Sections 2 and 3 found no evidence
of similar levels of disbondment or corrosion.
After a thorough examination, engineers recommended abrasive blast cleaning prior to applying
heat-shrink sleeves for future installations rather
than the standard brush cleaning of connections.
Another possible solution was liquid polyurethane
or epoxy applied at the joints. The disbonded coating
Corrosion Inhibitors in Deepwater
Deepwater projects can pose unique challenges
for corrosion control because the completions
are usually located at the seafloor and flowlines
must come to the surface or back to shore. A
deepwater field located in the southern Niger
delta demonstrates the use of inhibitors to combat CO2-induced corrosion (Figure 17).39
The production path for deepwater wells
passes through cold water, which can subject the
originally hot fluids in the flow stream to rapid
cooling. Conversely, inhibitor injection is often
through long umbilicals that are subjected to
temperature contrasts between the surface and
subsea wellheads. Injection of inhibitors is further complicated by the normally high flowing
pressures associated with deepwater production.
Temperature extremes, pressure extremes
and long umbilicals combine to affect inhibitor
FPSO vessel
NIGERIA
COTE
GHANA
D’IVOIRE
Niger Delta
field
Gulf of Guinea
CAMEROON
GABON
Subsea
wellheads
Flowlines and
umbilicals
Figure 17. Niger delta subsea operations and a floating production, storage, and offloading (FPSO) vessel. Production from subsea wellheads (yellow) at a
field in the Niger delta off the coast of Nigeria (inset) is sent to an FPSO. Oil is transferred to tankers, and natural gas is piped directly to the mainland.
46
Oilfield Review
38.Roche M: “The Problematic of Disbonding of Coatings
and Corrosion with Buried Pipelines Cathodically
Protected,” presented at the 10th European Federation
of Corrosion, Nice, France, September 12–16, 2004.
39.Jenkins A: “Corrosion Mitigation in a Deepwater
Oilfield Case Study,” paper IBP1194_15, presented at the
Rio Pipeline Conference and Exposition, Rio de Janeiro,
September 22–24, 2015.
40.API: “Attributes of Production Chemicals in Subsea
Production Systems,” Washington, DC: API,
API Technical Report 17TR6, 2012.
41.Jenkins, reference 39.
May 2016
Inhibitor
Dose Rate, ppm
Uninhibited
Corrosion Rate, mpy
Inhibited
Corrosion Rate, mpy
Protection, %
DS-1617 inhibitor
10
173.01
4.18
97.58
DS-1617 inhibitor
20
156.43
0.98
99.37
Inhibitor
Dose Rate, ppm
Corrosion Rate, mpy
Protection, %
None
—
71.04
—
DS-1617 inhibitor
20
1.16
98.37
Figure 18. Corrosion testing of the DS-1617 inhibitor. Technicians conducted kettle tests with fluids
representative of field conditions to evaluate the effectiveness of the DS-1617 inhibitor (top). They
also performed autoclave testing at high temperature (bottom). The corrosion rate is in milli-inches of
penetration/year (mpy).
Engineers developed the DS-1617 deepwater
corrosion inhibitor to meet the challenges of
this facility.
To qualify this inhibitor, they tested the
chemicals in accordance with the API TR 17TR6
standard, which requires replicating the temperatures and pressures experienced by the inhibitor
during deployment through the umbilicals.40 The
evaluation included high-pressure flow-loop stability tests. The engineers conducted additional
tests to look at resistance to hydrate formation,
thermal aging and compatibility with seawater.
Because the operator was concerned about foaming in the glycol regeneration unit, the inhibitor
was tested for foaming tendency.
Laboratory technicians performed kettle
tests using the DS-1617 inhibitor at 20 ppm,
which is a relatively low dosage; the corrosion
rate was reduced by 99% (Figure 18). They also
performed high-temperature autoclave testing
on carbon steel coupons. The samples were subjected to test fluids that had corrosion inhibitor
and to pressurized CO2 heated to 120°C [248°F].
The results indicated a 98% reduction in the
corrosion rate.41 The 20 ppm concentration
yielded corrosion rates of about 0.00016 in./year
[0.004 mm/year]. For corrosion rate, the standard industry units are milli-inches/year, or mpy.
For this test, the corrosion rate was equivalent to
0.16 mpy. Test technicians reported no foaming
problems associated with the inhibitor.
The operator adopted the use of the DS-1617
inhibitor and monitored corrosion at six locations on the FPSO. No corrosion monitoring
was installed on the deepwater flowlines. The
DS-1617 inhibitor was injected at a 100-ppm
rate, which is a lower rate than the initial inhibitor that was deemed insufficient. Criteria for
corrosion protection established by the operator was a rate below 0.05 mpy [0.0013 mm/year].
Testing at all six locations indicated corrosion
rates below the target rate (Figure 19). Based on
the testing, the operator implemented the use of
the DS-1617 inhibitor.
6.0
Low-pressure separator A
Low-pressure separator B
5.0
Corrosion rate, mpy
stability, performance and properties. Thorough
testing of the inhibitors is required to ensure
corrosion controlling properties are maintained,
that the injected chemicals remain stable and
that the inhibitors can be reliably delivered via
the umbilicals into the flow stream.
Another risk in deepwater production is the
formation of hydrates—ice-like solids of water
and gas that form above the normal freezing point
of water—that can plug flowlines. To ensure corrosion controlling properties are maintained,
inhibitors must be thoroughly tested to confirm
that the injected chemicals remain stable and
that the inhibitors can be reliably delivered via
umbilicals into the flow stream.
These conditions were faced by an operator
of a deepwater production platform in Nigeria.
The platform served nine wells drilled in water
depth of 1,030 m [3,380 ft]. The operator used
subsea completions that included five manifolds
and eight production flowlines and risers. The
flowlines were connected to a floating production, storage, and offloading (FPSO) vessel that
had 320,000 m3 [2 million bbl] of onsite storage
capacity. Produced oil flowed to the FPSO for
transfer to tankers. Produced gas was directed to
shore via pipelines.
The pipelines used to transport the oil and
gas were constructed of carbon steel. The flowing pressure from the wells averaged 80 bar
[1,160 psi], and the average temperature was
85°C [185°F]. The water cut was 45% and the
natural gas contained about 1.4% CO2. The combination of produced water (brine) and CO2
presented a high corrosion-rate potential for
the low-carbon steel. In wet gas pipelines such
as these, produced water has a tendency to condense at the top of the pipe, allowing top-of-line
corrosion; the presence of both water and CO2
accelerates corrosion.
Engineers installed chemical umbilicals of
1 to 20 km [0.6 to 12.4 mi] to inject corrosion
inhibitor into the deepwater production flowlines. As the project progressed, engineers at
M-I SWACO, a Schlumberger company, reevaluated the initial inhibitor used in the project,
which also protected the topside piping and
storage vessels, and deemed it to be insufficient.
Bulk oil treater
Target corrosion rate
4.0
3.0
2.0
1.0
0.0
0
0.5
1.0
1.5
2.0
2.5
3.0
Time, hr
3.5
4.0
4.5
5.0
6.0
Figure 19. Corrosion monitoring at a production facility. The operator injected DS-1617 inhibitor into
the flowlines of producing wells using underwater umbilicals. The corrosion rate of the flowlines was
monitored at the low-pressure separator A (blue), low-pressure separator B (red) and the bulk oil
treater (green) as well as at three other locations (not shown). The corrosion rate dropped below the
target level (black) established by the operator. Corrosion rates remained below the threshold at all
test sites for the duration of the testing period.
47
Anode
Water Depth, m
Weight Loss, %
1
13
13
2
73
31
3
116
25
4
116
39
Figure 20. Anode corrosion after eight years of service in the North Sea.
North Sea Cathodic Protection
North Sea production platforms routinely use
cathodic protection. On one platform, the operator installed 10 sacrificial anodes below the surface of the water and left them in place for eight
years. The anodes were composed of zinc, silver
and silver chloride and were located at various
depths and locations on the plaform.42 The system
was designed to protect the structure for a minimum of 20 years. Engineers monitored the output
current from three of the anodes over the period.
The anodes were removed and inspected at the
end of eight years.
After retrieval, the sacrificial anodes were
cleaned and weighed (Figure 20). Technicians
determined changes in physical dimensions and
measured electrical properties. Four anodes
were analyzed for the study. The reduction of
anodes that had been placed in deeper water was
greater than that of those placed in shallower
water. Some of the anodes were so corroded that
visual inspection was difficult (Figure 21).
The original 20-year design projected that at
eight years, the anodes should be reduced by 40%;
however, the average weight loss of the anodes
was only 24%. The engineers concluded that the
original design, although conservative, would
protect the structure for at least 20 years. Based
on the results of the study, a model was established for periodic inspections to be performed.
New Developments in Corrosion Control
Controlling corrosion has been an ongoing
battle between humans and nature for millennia. Since scientists such as Sir Humphry Davy
and Michael Faraday discovered some of the
underlying physics that explained corrosion,
various methodologies have been adopted and
adapted. Modern scientific understanding and
new technologies are combining to improve
the tools available to fight the unending battle
with corrosion.
One area of emerging materials science is
nanoparticles and nanostructures.43 Having surface thickness of 1 to 100 nm, these coating materials have unique properties that may make them
almost impervious to corrosion. Nanoparticles
and nanostructures may be deposited on metal
surfaces as films, similar to film-forming techniques, but because of nanoparticles’ greater
persistence, reapplying them is unnecessary. The
surfaces also become super-slick—exhibiting
low friction coefficients—which reduces wear
and increases durability. Such surfaces are also
less likely to experience biofouling.44
The battle against corrosion will never
be won; entropy will eventually win the war.
Humans will, however, continue to search for
effective means to combat this nemesis. The
costs of ignoring the problem are too great and
the consequences of failure can be potentially
catastrophic. At least in the oil field, operators
are armed with knowledge, science and effective
tools that allow them to actively manage or mitigate the effects of corrosion. —DEA/TS
Figure 21. Cathodic protection on a North Sea platform. Anodes were recovered
after eight years of service from a North Sea platform. After the anodes were
cleaned and weighed, technicians were able to determine the effectiveness of
the anodes at protecting the structure.
42.Roche M: “Offshore Cathodic Protection: The Lessons of
Long-Term Experience,” paper OMC-2005-020, presented
at the 7th Offshore Mediterranean Conference and
Exhibition, Ravenna, Italy, March 16–18, 2005.
43.El-Meligi AA: “Nanostructure of Materials and Corrosion
Resistance,” in Aliofkhazraei M (ed): Developments in
Corrosion Protection. Rijeka, Croatia: InTech (2014): 3–23.
48
44.Tesler AB, Kim P, Kolle S, Howell C, Ahanotu O and
Aizenberg J: “Extremely Durable Biofouling-Resistant
Surfaces Based on Electrodeposited Nanoporous
Tungstite Films on Steel,” Nature Communications 6,
no. 8649 (October 20, 2015).
Oilfield Review
Contributors
Nausha Asrar is the Manager for Materials Support
and Failure Analysis at the Schlumberger Houston
Pressure and Sampling and Formation Evaluation
Centers in Sugar Land, Texas, USA. He began his
career with Schlumberger in 2005 as a senior materials scientist. He previously worked for Shell Global
Solutions in the US, the Saudi Basic Industries
Corporation Technology Center and Saline Water
Conversion Corporation, both in Saudi Arabia, and
as principal corrosion engineer at the Research and
Development Center for Iron and Steel for the Steel
Authority of India, Ltd. A NACE certified material
selection and design specialist, Nausha is a member
of NACE, ASM and SPE as well as a life member of the
Indian Institute of Metals; he is the author of more
than 60 technical papers and reviews on corrosion,
phase diagrams, composite materials and failure cases.
He received an MS degree in chemistry from Aligarh
Muslim University, Uttar Pradesh, India, and a PhD
degree in materials science and engineering from the
Moscow State University.
Bruce MacKay is Client Support Manager for the
Schlumberger North America fracturing and cementing operations in Sugar Land, Texas. He has worked
as a chemical problem solver in various capacities
for Schlumberger for 10 years, spanning the R&D
spectrum from research to product development to
technology implementation. He has authored 12 peerreviewed scientific journal articles and five SPE papers
and has been granted several patents on chemical
technologies related to oilfield applications. He has
been a speaker on the importance of chemistry in oilfield development to a variety of audiences, including
the US National Academy of Sciences, the American
Chemical Society and the National Aeronautics and
Space Administration Jet Propulsion Laboratory.
Bruce was a Natural Sciences and Engineering
Research Council of Canada postdoctoral research
scholar at the California Institute of Technology,
Pasadena, USA. He earned a BS degree in chemistry
and a PhD degree in inorganic chemistry from the
University of British Columbia, Vancouver, Canada.
Øystein Birketveit is Technical Manager for Production
Technologies for M-I SWACO, a Schlumberger company,
in Bergen, Norway. For the past 18 years, he has
specialized in the field of corrosion. Prior to joining
M-I SWACO, Øystein worked for Statoil and for Det
Norske Veritas. He earned his MSc degree in materials
and electrochemistry from the Norwegian University of
Science and Technology, Trondheim.
Denis Mélot is a Nonmetallic Materials Expert with
the technology department of Total Upstream, in Paris.
Using his foundation of studies in polymer science,
his focus is on nonmetallic materials and corrosion.
Prior to beginning work with Total in 2003, he was a
researcher in the R&D department of Elf Atochem,
which is now Arkema, in Serquigny, France. He then
spent six years as the technical manager for pipe
coating products with the company. Denis chaired
the ISO 12736 working group on wet thermal insulation systems, was a member of pipeline coatings work
group ISO 21809 and holds certifications from the
Association pour la Certification et la Qualification
en Peinture Anticorrosion and Faglig Råd for
Opplæring og Sertifisering av Inspektører innen
Overflatebehandling . He holds numerous patents in
his field and has coauthored several papers on the
subject of coatings and corrosion. Denis has a degree
in materials science from the École Universitaire
D’Ingénieurs de Lille, France, and received his PhD
degree in polymer science from Université de Lille.
Joshua E. Jackson is the CEO of G2MT LLC as well as
the cofounder of G2MT Laboratories, LLC in Houston.
G2MT Labs is a metallurgical consulting and analysis
company that performs nondestructive materials characterization to evaluate residual stress mechanical
properties and other critical parameters including the
effects of corrosion. His scientific focus areas include
corrosion analysis, high-temperature materials, hydrogen absorption effects, failure analysis and statistics.
Joshua is the coauthor of numerous papers in the field
of materials science covering subjects including nondestructive testing, metallurgy, welding, corrosion and
hydrogen. He obtained BS degrees in both mathematics and physics from the Massachusetts Institute of
Technology, Cambridge, USA, and MS and PhD degrees
in metallurgical and materials engineering from the
Colorado School of Mines, Golden, USA.
Alyn Jenkins, based in Aberdeen, serves as the Global
Asset Integrity Manager for Schlumberger Production
Technologies. He manages asset integrity product
lines that include corrosion inhibitors, biocides, H2S
scavengers and oxygen scavengers and is responsible
for research and development projects related to
corrosion. He began his career in 1998 with Clariant
Oil Services in Aberdeen and then worked for Baker
Hughes in Liverpool, England. Alyn joined M-I SWACO
in 2005 as a corrosion specialist in Stavanger and then
served as lead integrity management specialist. Alyn
holds BS and MS degrees, both in chemistry, from the
University of Wales, Bangor.
May 2016
Jan Scheie is a Project Leader and Account Manager
for Production Technologies (PT) in Schlumberger
Norge A/S in Stavanger, where he serves customers in
Scandinavia. He has also been an account manager
for production technologies, an international sales
manager and an area manager for production chemicals in Stavanger. He has worked for M-I SWACO in
market development for the eastern hemisphere, as
technical manager in the Middle East and CIS, as sales
manager in South Asia and as principal engineer for
developing sales strategy in mainland Europe. He is a
member of TEKNA, the Norwegian Society of Graduate
Technical and Scientific Professionals, the SPE and
the National Association of Corrosion Engineers. He
received an MSc degree in chemical engineering from
the Norwegian University of Science and Technology,
Trondheim, Norway, and an MBA degree from
Thunderbird School of Global Management, Glendale,
Arizona, USA.
Marko Stipaničev is Corrosion Discipline Lead for
Schlumberger Production Technologies in Bergen,
Norway. Upon graduation from the University of
Zagreb, Croatia, he worked as an external consultant
on industry related projects at the Faculty of Chemical
Engineering and Technology, in Croatia. Beginning in
2010, he worked as a research engineer for Det Norske
Veritas in Bergen, investigating corrosion-based failures
and performing root cause analysis studies. He joined
M-I SWACO in 2013 as a corrosion specialist, working
in Bergen, and in 2015, he was named the corrosion
discipline lead. Marko is responsible for Schlumberger
corrosion products, which include inhibitors, biocides,
scavengers and nutrients. He has authored and coauthored numerous papers and publications related to
corrosion and corrosion management. He holds an MSc
degree in chemical engineering and technology from
the University of Zagreb and a PhD degree in environmental process and biocorrosion management from the
Université de Toulouse, France.
Jean Vittonato, is Head of the Total E&P Technology
Division corrosion department in Pau, France. He
is responsible for the headquarters’ corrosion team
and provides technical assistance to projects and
operating subsidiaries worldwide. He started work in
1999 focusing on cathodic protection with COREXCO,
an engineering cathodic protection company, where
he was in charge of designing cathodic protection
systems for both onshore and offshore and for installation, monitoring and maintenance follow-up. In 2006,
he joined Total as a corrosion specialist and was in
charge of cathodic protection activities. He provided
support for projects for both Total E&P and operating
subsidiaries and was in charge of research projects
related to cathodic protection. He spent three years
in Republic of the Congo as the head of the Total corrosion department, where he supervised all projects
related to corrosion. Jean is a certified Cathodic
Protection Specialist with the National Association
of Corrosion Engineers and with the Centre Français
de la Protection Cathodique and is chair of the
ISO TC 67 SC2 GW11 working group on cathodic
protection of pipelines. He obtained an engineering degree from Institut National Polytechnique de
Grenoble, France.
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