SUBSEA PIPELINE
INTEGRITY
AND RISK
MANAGEMENT
YONG BAI
QIANG BAI
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Library of Congress Cataloguing-in-Publication Data
Bai, Yong, author.
Subsea pipeline integrity and risk management / by Yong Bai, Qiang Bai. – First edition.
pages cm
Summary: “In most subsea developments, oil and gas productions are transported from subsea well to
platform in multiphase flow without separation process. Corrosion represents increasing challenges for
the operation of subsea pipelines. Corrosion can be defined as a deterioration of a metal, due to chemical
or electrochemical between the metal and its environment. The tendency of a metal to corrode depends
on a given environment and the metal type”– Provided by publisher.
Includes bibliographical references and index.
ISBN 978-0-12-394432-0 (hardback)
1. Underwater pipelines–Corrosion. 2. Underwater pipelines–Design and construction. 3. Offshore
structures–Design and construction. 4. Offshore oil well drilling–Safety measures. 5. Offshore oil
industry–Risk management. I. Bai, Qiang, author. II. Title.
TC1800.B354 2014
621.8’67209162–dc23
2013047933
British Library Cataloguing in Publication Data
A catalogue record for this book is available from the British Library
For information on all Gulf Professional publications
Visit our web site at store.elsevier.com
Printed and bound in USA
14 15 16 17 18 10 9 8 7 6 5 4 3 2 1
ISBN: 978-0-12-394432-0
FOREWORD
I am delighted to write a brief Foreword to this extensive handbook for
subsea pipeline integrity and risk management. It is often a challenge to
find a single book that discusses all aspects of subsea pipeline integrity and
risk management in sufficient detail that the practicing engineer can have
this book or volume of books as a desk reference for a large range of subsea
topics, instead of the engineer having to search for specific subject matter in
Conference Proceedings. And the authors have succeeded in accomplishing
just that. The effort it took in writing well over a 450 pages of text and
formulae and cross-checking was truly a labor of love and dedication to
the profession of subsea pipeline engineers, and for those readers who
wish to know more about a particular subject, the list of references at the
end of each chapter is truly outstanding.
Frans Kopp, January 2014
xi
j
PREFACE
It has been 8 years since our book “Subsea Pipelines and Risers” (SPR) was
published by Elsevier. As a new sister book of “Subsea Pipeline Design,
Analysis and Installation”, this new book “Subsea Pipeline Integrity and
Risk Management” reflects upon the new pipeline technologies in integrity
and risk management developed by the oil and gas industry, where the
authors apply them in design, consulting and integrity management. This
book is written for engineers who work in the field of subsea pipeline
engineering.
Pipeline integrity management has become matured and applied to the
operation and maintenance. Risk and reliability management of pipelines
became ever more critical in the subsea industry for QRA assessment,
risk and environmental impact study as well as preparation of emergency
response plans. The risk and reliability assessment has also been successfully
applied for the determination of partial safety factors in design criteria.
The industry has been seeking new tools for subsea pipeline inspection
and integrity management, whether the pig launchers are available or not.
The authors have been also involved in the development of new tools for
non-piggable pipelines, flexible pipelines and composite RTP pipelines.
We hope that these two books (Subsea Pipeline Design, Analysis and
Installation, and Subsea Pipeline Integrity and Risk Management) are useful
reference sources of subsea pipeline design, analysis, installation, integrity
management and risk management for subsea engineers.
The authors would like to thank our graduate students, PhD and postdoctoral fellows at Zhejiang University and Harbin Engineering University,
who provided editing assistance (Mr. Jiwei Tang, Mr. Carl Bai & Mr. Akira
Bai) and initial technical writing (Mr. Gao Tang, Ms. Yin Zhang, Mr.
Shiliang He, Mr. Hongdong Qiao, Mr. Weidong Ruan, Mr. Hui Shao,
and Ms. Shahirah Abu Baka), thank Zhejiang University for their support
for publishing this book.
Thanks to all the persons involved in reviewing and updating the books,
particularly Ms. Anusha Sambamoorthy of Elsevier, who provided editory
assistance. We specially thank our families and friends for their supports.
Dr. Qiang Bai & Prof. Yong Bai
Houston, USA
xiii
j
CHAPTER
1
Corrosion and Corroded Pipelines
Contents
1. Introduction
2. Corrosion Defect Prediction
Introduction
Sweet: Carbon Dioxide Corrosion
Sour: Hydrogen Sulfide Corrosion
Inspection for Corrosion Defects
Corrosion Defect Growth
Corrosion Predictions
3
4
4
5
6
7
7
8
10
11
18
18
19
19
20
20
21
21
22
23
23
23
24
24
CO2 Corrosion Models Comparison
Sensitivity Analysis for CO2 Corrosion Calculation
3. Remaining Strength of Corroded Pipe
NG-18 Criterion
B31G Criterion
Maximum Allowable Design Pressure
Maximum Allowable Defect Length and Depth
The Safe Maximum Pressure Level
Evaluation of Existing Criteria
Corrosion Mechanism
Spiral Corrosion
Pits Interaction
Groove Interactions
Corrosion in Welds
Effect of Corrosion Width
References
1. INTRODUCTION
In most subsea developments, oil and gas production is transported from the
subsea well to a platform in multiphase flow without a separation process.
Corrosion represents increasing challenges for the operation of subsea
pipelines. Corrosion can be defined as a deterioration of a metal due to
chemical or electrochemical reactions between the metal and its environment. The tendency of a metal to corrode depends on a given environment
and the metal type.
The presence of carbon dioxide (CO2), hydrogen-sulfide (H2S), and free
water in the production fluid can cause severe corrosion problems in oil and
Subsea Pipeline Integrity and Risk Management
ISBN 978-0-12-394432-0
http://dx.doi.org/10.1016/B978-0-12-394432-0.00001-9
Ó 2014 Elsevier Inc.
All rights reserved.
3
j
4
Yong Bai and Qiang Bai
gas pipelines. Internal corrosion in wells and pipelines is influenced by
temperature, CO2 and H2S content, water chemistry, flow velocity, oil or
water wetting, and the composition and surface condition of the steel.
Corrosion-resistant alloys, such as 13% Cr steel and duplex stainless steel, are
often used in downhole piping of subsea equations and structures. However,
for long-distance pipelines, carbon steel is the only economically feasible
alternative and corrosion has to be controlled and the flowline protected
from the corrosion both internally and externally.
This chapter develops prediction models of corrosion defects and the
reliability based design and requalification criteria for assessing corroded
pipelines. This evaluation focuses on the following interrelated issues:
• Corrosion defect growth.
• Checking burst strength (allowable versus maximum internal service
pressure).
• Checking bending capacity (allowable versus maximum external service
pressure, bending moment, and axial load).
• Checking adequacy of residual corrosion allowance for remaining service life.
• Inspecting corrosion defects.
• Updated inspection and maintenance programs.
2. CORROSION DEFECT PREDICTION
Introduction
Two types of corrosions may occur in the oil and gas pipeline system when
CO2 and H2S are present in the hydrocarbons fluid: sour corrosion and
sweet corrosion. Sweet corrosion occurs in systems containing only carbon
dioxide or a trace of hydrogen sulfide (H2S partial pressure < 0.05 psi). Sour
corrosion occurs in systems containing hydrogen sulfide above a partial
pressure of 0.05 psia (0.34 kPa) and carbon dioxide.
When corrosion products are not deposited on the steel surface, very
high corrosion rates of several millimeters per year (mm/yr) can occur. This
“worst case” corrosion is the easiest type to study and reproduce in the
laboratory. When CO2 dominates the corrosivity, the corrosion rate can be
reduced substantially under conditions where iron carbonate can precipitate
on the steel surface and form a dense and protective corrosion product film.
This occurs more easily at high temperatures or high pH values in the water
phase. When H2S is present in addition to CO2, iron sulfide films are
formed rather than iron carbonate, and protective films can be formed at
Corrosion and Corroded Pipelines
5
lower temperatures, since iron sulfide precipitates much more easily than
iron carbonate. Localized corrosion with very high corrosion rates can
occur when the corrosion product film does not give sufficient protection,
and this is the most feared type of corrosion attack in oil and gas pipelines.
Sweet: Carbon Dioxide Corrosion
Carbon dioxide is composed of one atom of carbon with two atoms of
oxygen. It is a corrosive compound found in natural gas, crude oil,
condensate, and produced water. It is one of the most common environments in the oil field industry where corrosion occurs. The CO2 corrosion
is enhanced in the presence of both oxygen and organic acids, which can
dissolve iron carbonate scale and prevent further scaling.
Carbon dioxide is a weak acidic gas and becomes corrosive when dissolved in water. However, CO2 must hydrate to carbonic acid, H2CO3,
which is a relatively slow process, before it becomes acidic. Carbonic acid
causes a reduction in the pH of water and results in corrosion when it comes
in contact with steel.
Areas where CO2 corrosion is most common include flowing wells, gas
condensate wells, areas where water condenses, tanks filled with CO2,
saturated produced water, and pipelines, which are generally corroded at a
slower rate because of lower temperatures and pressures. The CO2 corrosion is enhanced in the presence of both oxygen and organic acids, which
can act to dissolve iron carbonate scale and prevent further scaling.
The maximum concentration of dissolved CO2 in water is 800 ppm.
When CO2 is present, the most common forms of corrosion include uniform corrosion, pitting corrosion, wormhole attack, galvanic ringworm
corrosion, heat affected corrosion, mesa attack, raindrop corrosion, erosion
corrosion, and corrosion fatigue. The presence of carbon dioxide usually
means no H2 embrittlement.
Rates of CO2 corrosion are greater than the effect of carbonic acid
alone. Corrosion rates in a CO2 system can reach very high levels (thousands
of millions per year), but it can be effectively inhibited. Velocity effects are
very important in the CO2 system: Turbulence is often a critical factor in
pushing a sweet system into a corrosive regime. This is because it either
prevents formation or removes a protective iron carbonate (siderite) scale.
Products of CO2 corrosion include iron carbonate (siderite, FeCO3),
iron oxide, and magnetite. Corrosion product colors may be green, tan, or
brown to black. This can be protective under certain conditions. Scale itself
can be soluble. Conditions favoring the formation of a protective scale are
6
Yong Bai and Qiang Bai
elevated temperatures, increased pH as occurs in bicarbonate-bearing waters, and lack of turbulence, so that the scale film is left in place. Turbulence
is often the critical factor in the production or retention of a protective iron
carbonate film. Iron carbonate is not conductive. Therefore, galvanic
corrosion cannot occur. Therefore, corrosion occurs where the protective
iron carbonate film is not present and is fairly uniform over the exposed
metal. Crevice and pitting corrosion occur when carbonate acid is formed.
Carbon dioxide can also cause embrittlement, resulting in stress corrosion
cracking.
Sour: Hydrogen Sulfide Corrosion
Hydrogen sulfide is a flammable and poisonous gas. It occurs naturally in
some groundwater. It is formed from decomposing underground deposits of
organic matter, such as decaying plant material. It is found in deep or
shallow wells and also can enter surface water through springs, although it
quickly escapes to the atmosphere. Hydrogen sulfide often is present in wells
drilled in shale or sandstone or near coal or peat deposits or oil fields.
Hydrogen sulfide gas produces an offensive “rotten egg” or “sulfur
water” odor and taste in water. In some cases, the odor may be noticeable
only when the water is initially turned on or when hot water is run. Heat
forces the gas into the air, which may cause the odor to be especially
offensive in a shower. Occasionally, a hot water heater is a source of
hydrogen sulfide odor. The magnesium corrosion control rod present in
many hot water heaters can chemically reduce naturally occurring sulfates to
hydrogen sulfide.
Hydrogen sulfide (H2S) occurs in approximately 40% of all wells. Wells
with large amounts of H2S are usually labeled sour; however, only wells with
10 ppm or above can be labeled sour. Partial pressures above 0.05psi H2S are
considered corrosive. The amount of H2S appears to increase as the well
grows older. The H2S combines with water to form sulfuric acid (H2SO4), a
strongly corrosive acid. Corrosion due to H2SO4 is often referred to as sour
corrosion. Since hydrogen sulfide combines easily with water, damage to
stock tanks below water levels can be severe.
Water with hydrogen sulfide alone does not cause disease. However,
hydrogen sulfide forms a weak acid when dissolved in water. Therefore, it is a
source of hydrogen ions and is corrosive. It can act as a catalyst in the absorption of atomic hydrogen in steel, promoting sulfide stress cracking (SSC)
in high strength steels. Polysulfides and sulfanes (free acid forms of polysulfides) may be formed when hydrogen sulfide reacts with elemental sulfur.
Corrosion and Corroded Pipelines
7
The corrosion products are iron sulfides and hydrogen. Iron sulfide
forms a scale at low temperatures and can act as a barrier to slow corrosion.
The absence of chloride salts strongly promotes this condition, and the
absence of oxygen is absolutely essential. At higher temperatures, the scale is
cathodic in relation to the casing, and galvanic corrosion starts. The chloride
forms a layer of iron chloride, which is acidic and prevents the formation of
FeS layer directly on the corroding steel, enabling the anodic reaction to
continue. The hydrogen produced in the reaction may lead to hydrogen
embrittlement. A nuisance associated with hydrogen sulfide includes its
corrosiveness to metals such as iron, steel, copper, and brass. It can tarnish
silverware and discolor copper and brass utensils.
Inspection for Corrosion Defects
The scope of the assessment for corrosion defects consists of a proper
characterization of defects by thickness profile measurements and an initial
screening phase to decide whether detailed analysis is required.
The assessment of a single isolated defect is to be based on a critical
profile defined by the largest measured characteristic dimensions of the
defect (e.g., depth, width, length) and properly calibrated safety and uncertainty factors, to account for uncertainties in the assessment and thickness
measurements.
A distance equivalent to the normal pipe wall thickness may be used as a
simple criterion of separation for colonies of longitudinally oriented pits
separated by a longitudinal distance or parallel longitudinal pits separated by
a circumferential distance. For longitudinal grooves inclined to the pipe axis,
• If the distance, x, between two longitudinal grooves of length L1 and L2
is greater than either L1 or L2, then the length of corrosion defect L is L1
or L2, whichever is greater. It can be assumed that there is no interaction
between the two defects.
• If the distance, x, between two longitudinal grooves of length L1 and L2
is less than either L1 or L2, it is assumed that the two defects are
fully interacted and the length of the corrosion defect L is to be taken as
L ¼ L1 þ L2 þ x.
Corrosion Defect Growth
The corrosion defect depth, d, after the time, T, of operation may be
estimated by using an average corrosion rate, Vcr:
d ¼ d0 þ Vcr $T
[1.1]
8
Yong Bai and Qiang Bai
where d0 is defect depth at present time.
The defect length may be assumed to grow in proportion with the
depth, hence:
Vcr $T
[1.2]
L ¼ L0 1 þ
d0
where L and L0 are defect lengths at the present time and the time T later.
Corrosion Predictions
The CO2 corrosion of carbon steel used in oil production and transportation, when liquid water is present, is influenced by a large number of
parameters, some of which follow:
• Temperature.
• CO2 partial pressure.
• Flow (flow regime and velocity).
• pH.
• Concentration of dissolved corrosion product (FeCO3).
• Concentration of acetic acid.
• Water wetting.
• Metal microstructure (welds).
• Metal prehistory.
The detailed influence of these parameters is still poorly understood and
some of them are closely linked to each other. A small change in one of
them may influence the corrosion rate considerably.
Various prediction models have been developed and are used by
different companies. Among them are the de Waard et al. model (Shell),
CORMED (Elf Aquitaine), LIPUCOR (Total), and a new electrochemically based model developed at IFE. Due to the complexity of the
various corrosion controlling mechanisms involved and a built-in
conservatism, the corrosion models often overpredict the corrosion rate
of carbon steel.
The Shell model for CO2 corrosion is most commonly used in oil and
gas industry. The model is mainly based on the de Waard et al.’s equation
published in 1991 [1]. Starting from a “worst case” corrosion rate prediction, the model applies correction factors to quantify the influence of
environmental parameters and corrosion product scale formed under
various conditions. However, the first version of the model was published in
1975, and it has been revised several times to make it less conservative by
including new knowledge and information. The original formula of de
Corrosion and Corroded Pipelines
9
Waard and Milliams implied certain assumptions that necessitated the
application of correction factors for the influence of environmental parameters and for the corrosion product scale formed under various
conditions.
Rates of CO2 corrosion in pipelines made of carbon steel may be
evaluated using industry accepted equations, which preferably combine
contributions from flow-independent kinetics of the corrosion reaction at
the metal surface, with the contribution from flow-dependent mass transfer
of dissolved CO2.
The corrosion rate calculated from the original formula with its
correction factors is independent of the liquid velocity. To account for the
effect of flow, a new model was proposed, which takes the effect of mass
transport and fluid velocity into account by means of a so-called resistance
model:
Vcr ¼
1
Vr
1
þ V1m
[1.3]
where the corrosion rate Vcr is in mm/year; Vr is the flow-independent
contribution, denoted the reaction rate; and Vm is the flow-dependent
contribution, denoted the mass transfer rate.
In multiphase turbulent pipeline flow, Vm depends on the velocity and
the thickness of the liquid film, while Vr depends on the temperature, CO2
pressure, and pH. For example, for pipeline steel containing 0.18% C and
0.08% Cr, the equations for Vr and Vm for liquid flow in a pipeline are
logðVr Þ ¼ 4:93
1119
þ 0:58$log pCO2
Tmp þ 273
[1.4]
where Tmp is pipeline fluid temperature in C, and the partial pressure pCO2
of CO2 is in bar. The partial pressure pCO2 can be found by
pCO2 ¼ nCO2 $popr
[1.5]
where nCO2 is the fraction of CO2 in the gas phase, and popr is the operating
pressure in bar.
The mass transfer rate Vm, is approximated by
Vm ¼ 2:45$
U 0:8
$pCO2
d0:2
[1.6]
where U is the liquid flow velocity in m/s, and d is the inner diameter in m.
10
Yong Bai and Qiang Bai
CO2 Corrosion Models Comparison
The corrosion caused by the incidences of CO2 represents the greatest risk
to the integrity of carbon steel equipment in a production environment and
is more common than damage related to fatigue, erosion, or stress corrosion
cracking. NORSOK, Shell, as well as other companies and organizations
have developed models to predict the corrosion degradation.
NORSOK’s standard M-506 may be used to calcuate the CO2 corrosion rate which is an empirical model for carbon steel in water containing
CO2 at different temperatures, pH, CO2fugacity, and wall shear stress. The
NORSOK model covers only the corrosion rate calculation where CO2 is
the corrosive agent. It does not include additional effects of other constituent, which may influence the corrosivity, such as H2S, which commonly
appears in the production flowlines. If such constituent is present, the effect
must be evaluated separately. None of the de Waard et al. models includes
the H2S effect.
Figure 1.1 shows an example of corrosion rate prediction in a subsea gas
condensate pipeline. Here, two of the most commonly used corrosion
prediction models were combined with a three-phase fluid flow model to
calculate corrosion rate profiles along a pipeline. This can help identify
locations where variation in flow regime, flow velocity, and water accumulation may increase the risk of corrosion damage. For this pipeline, the
temperature was 90 C at the inlet and 20 C at the outlet, and the decrease
in predicted corrosion rates toward the end of the pipeline is mainly a result
of the decreasing temperature. The lower corrosion rates close to the
FIGURE 1.1 Predicted Corrosion Rate in a Subsea Pipeline. Source: Nyborg [2]. (For color
version of this figure, the reader is referred to the online version of this book.)
Corrosion and Corroded Pipelines
11
pipeline inlet are due to the effect of protective corrosion films at high
temperatures, which is predicted differently by the two corrosion models
used. The peaks in predicted corrosion rates result from variation in flow
velocity due to variations in the pipeline elevation profile.
Sensitivity Analysis for CO2 Corrosion Calculation
Table 1.1 presents the base case for the following sensitivity analysis.
These data are based on the design operating data for a 10 in. production
flowline.
Total System Pressure and CO2 Partial Pressure
An increase in total pressure leads to an increase in corrosion rate because
pCO2 increases in proportion. With increasing the pressure, the CO2 fugacity
fCO2, should be used instead of the CO2 partial pressure, pCO2, since the
gases are not ideal at high pressures. The real CO2 pressure can be expressed
as
fCO2 ¼ a pCO2
[1.7]
where a is fugacity constant, which depends on pressure and temperature,
such as the following:
a ¼ 10Pð0:00311:4=T Þ for P 250 bar
a ¼ 10250ð0:00311:4=T Þ for P > 250 bar
Figures 1.2 and 1.3 present the effect of total pressure and CO2 partial
pressure on the corrosion rate, respectively. With increasing the total
pressure and CO2 partial pressure, the corrosion rate is greatly increased.
Table 1.1 Base Case for Sensitivity Analysis
Parameter
Units
Base Case
Total pressure
Temperature
CO2 in gas
Flow velocity
H2 S
pH
Water cut
Inhibitor availability
52
22.5
0.5
2.17
220
4.2
50%
50%
bar
C
Mole %
m/s
ppm
[d]
[d]
[d]
12
Yong Bai and Qiang Bai
System Temperature
Temperature has the effect of the formation of protective film. At lower
temperatures, the corrosion product can be easily removed by flowing
liquid. At higher temperatures, the film becomes more protective and less
FIGURE 1.2 Effect of Total Pressure on the Corrosion Rate. (For color version of this
figure, the reader is referred to the online version of this book.)
FIGURE 1.3 Effect of CO2 on the Corrosion Rate. (For color version of this figure, the
reader is referred to the online version of this book.)
Corrosion and Corroded Pipelines
13
easily washed away. Further increase in temperature results in a lower
corrosion rate and the corrosion rate goes through a maximum [1]. This
temperature is referred as the scaling temperature. At this temperature, pH
and Feþþ concentration form at the steel’s surface. At temperatures
exceeding the scaling temperature, the corrosion rates tend to decrease to
close to zero, according to De Waard et al. Tests in IFE Norway reveal that
the corrosion rate is still increasing when the design temperature is beyond
the scaling temperature [3].
Figure 1.4 shows the effect of temperature on the corrosion rate, where
the total pressure is 48 bar and the pH is equal to 4.2. The corrosion rate
increases with increasing the temperature, when the temperature is lower
than the scaling temperature.
H2S
Hydrogen sulfide can depress pH when it dissolves in a CO2 aqueous solution. The presence of H2S in CO2-brine systems can reduce the corrosion
rate of steel when compared to the corrosion rate without H2S at temperatures less than 80 C, due to the formation of a meta-stable iron sulfide
film. At higher temperatures, the combination of H2S and chlorides produce higher corrosion rates than just the CO2-brine system, since the
protective film is not formed.
FIGURE 1.4 Effect of Temperature on the Corrosion Rate. (For color version of this
figure, the reader is referred to the online version of this book.)
14
Yong Bai and Qiang Bai
The H2S at levels below the NACE criteria for sulfide stress corrosion
cracking (per MR0175, NACE publication) reduces general metal loss rates
but can promote pitting. The pitting proceeds at a rate determined by the
CO2 partial pressure and therefore CO2-based models are still applicable at
low levels of H2S. Where the H2S concentration is greater or equal to the
CO2 value or greater than 1 mol %, the corrosion mechanism may not be
controlled by CO2 and therefore CO2-based models may not be applicable.
pH
The pH affects the corrosion rate by affecting the reaction rate of cathodes
and anodes, therefore, the formation of corrosion products. The contamination of a CO2 solution with corrosion products reduces the corrosion
rate. The pH has a dominant effect on the formation of corrosion films, due
to its effect on the solubility of ferrous carbonate. An increase in pH slows
down the cathodic reduction of Hþ. Figure 1.5 presents the relationship
between the pH and corrosion rate. In a solution with a pH less than 7,
corrosion rate decreases with increasing pH.
Inhibitors and Chemical Additives
Inhibitors can reduce the corrosion rate by presenting a protective film. The
presence of the proper inhibitors with optimum dosage can maintain the
FIGURE 1.5 Effect of pH on Corrosion Rate. (For color version of this figure, the reader
is referred to the online version of this book.)
Corrosion and Corroded Pipelines
15
corrosion rate at 0.1 mm/year. Use of inhibitors can greatly decrease
corrosion rate and, therefore, increase pipeline life.
The impingement of sand particles can destroy the inhibitor film and,
therefore, reduce the inhibitor efficiency. Inhibitors also perform poorly in
low-velocity lines, particularly if the fluids contain solids, such as wax, scale,
or sand. Under such circumstances, deposits inevitably form at the 6 o’clock
position, preventing the inhibitor from reaching the metal surface. Flow
velocities below approximately 1.0 m/s should be avoided if inhibitors are
expected to provide satisfactory protection, and this is critical in lines
containing solids.
Inhibitor Efficiency versus Inhibitor Availability
When inhibitors are applied, there are two ways to describe the extent to
which an inhibitor reduces the corrosion rate, the use of inhibitor efficiency
(IE) and the use of the inhibitor availability (IA). A value of 95% for IE is
commonly used. However, inhibitors are unlikely to be constantly effective
throughout the design life. For instance, increased inhibitor dosage or better
chemicals increase the inhibitor concentration. It may be assumed that the
inhibited corrosion rate is unrelated to the uninhibited corrosivity of the
system, and all systems can be inhibited to 0.1 mm/year. The corrosion
inhibitor is not available 100% of the time and therefore corrosion will
proceed at the uninhibited rate for some periods.
Figure 1.6 shows the inhibited corrosion rate under different inhibitor
availability. The lines are based on the assumed existence of corrosion
inhibitors that can protect the steel to a corrosion rate CRmit (typically
0.1 mm/year) regardless of the uninhibited corrosion rate CRunmit,
taking into consideration the percentage of time IA the inhibitor is
available.
Chemical Additives
Glycol (or methanol) is often used as the hydrate preventer on a recycled
basis. If glycol is used without the addition of a corrosion inhibitor, there
is some benefit from the glycol. De Waard et al. produced a glycol
correction factor. However, if glycol and inhibitor are both used, little
additional benefit accrues from the glycol and it should be ignored for
design purpose.
Methanol is batch injected during startup until the flowline temperatures rise above the hydrate formation region and during extended
shutdown.
16
Yong Bai and Qiang Bai
FIGURE 1.6 Inhibited Corrosion Rate under different Inhibitor Availabilities. (For color
version of this figure, the reader is referred to the online version of this book.)
Single-Phase Flow Velocity
Single-phase flow refers to a flow with only one component, normally oil, gas,
or water through a porous media. Fluid flow influences corrosion by
affecting mass transfer and the mechanical removal of solid corrosion
products. The flow velocity used in corrosion model is identified as the true
water velocity. Figure 1.7 shows that the corrosion rate increases consistently with increased flow rate at low pH values.
Multiphase Flow
Multiphase flow refers to the simultaneous flow of more than one fluid phase
through a porous media. Most oil wells ultimately produce both oil and gas
from the formation and often produce water. Consequently, multiphase
flow is common in oil wells. The multiphase flow in a pipeline is usually
studied by flow regime and corresponding flow rate. Because of the various
hydrodynamics and the corresponding turbulence, multiphase flow further
influences the internal corrosion rate, in a significantly different way than
the influence of single-phase flow in the pipeline.
Water Cut
Water cut means the ratio of water produced compared to the volume of total
liquid produced. Corrosion from CO2 is mainly caused by water in contact
with the steel surface. The severity of the CO2 corrosion is proportional to
Corrosion and Corroded Pipelines
17
FIGURE 1.7 Effect of Flow Velocity on the Corrosion Rate. (For color version of this
figure, the reader is referred to the online version of this book.)
the time during which the steel surface is wet in the water phase. Thus, the
water cut is an important factor to influence the corrosion rate. However,
the effect of the water cut cannot be separated from the flow velocity and the
flow regime.
Free-Span Effect
Pipeline spanning can occur on a rough seabed or a seabed subjected to
scouring. The evaluation of allowable free-span length should be considered
to avoid the excessive yielding and fatigue. The localized reduction of wall
thickness influences the strength capacity of the pipeline, therefore, the
allowable free-span length. This is discussed in many reports and papers. It is
not within the scope of work for this chapter to assess yielding and fatigue of
free spans. Instead, a qualitative discussion is given on possible development
or acceleration of the development of corrosion.
Figure 1.8 shows at the middle point of the free spans. Additional
accumulated waters and marine organism may accelerate corrosion development. The flow regime and flow rates change. The corrosion defect
depth in the region close to the middle point is most likely deeper.
These three corrosion models were developed based on the results of
tests using water-only, that is, a 100% water cut, system in the laboratory.
18
Yong Bai and Qiang Bai
FIGURE 1.8 Effect of Free Spans on Corrosion Defect Development.
Therefore, the corrosion rate predicted with these models represents the
worst case corrosion rates. For comparison, the corrosion rate under the
flow condition with smaller water cut is generally lower than the worst case
rate. Therefore, the predictoion of corrosion rates with these models is very
conservative compared to the real corrosion rate in the field. With more
corrosion data from pipeline pigging, the accuracy of corrosion
rate prediction can be improved. However, the accuracy of corrosion rate
prediction still cannot be exaggerated, since the internal corrosion is
influenced by numerous parameters, as already discussed. The combination
of the corrosion rate prediction method and the pipeline pigging method
can provide a benchmark to pinpoint the weakest links in the pipeline,
predict the remaining life, and maintain the pipeline integrity.
3. REMAINING STRENGTH OF CORRODED PIPE
The design criteria for corroded pipelines are generally expressed as equations to determine the operating parameters:
• Maximum allowable length of defects.
• Maximum allowable design pressure for uncorroded pipelines.
• Maximum safe pressure.
A number of criteria exist to determine these operating parameters.
NG-18 Criterion
The NG-18 criterion developed in the late 1960s and early 1970s is used to
evaluate the remaining strength of corroded pipe [4]. It was developed for a
pipe with a longitudinal surface flaw:
1 AREA=AREA
0
Sp ¼ Sflow
[1.8]
1
AREA=AREA
1M
0
where
Sp ¼ predicted hoop stress level at failure
Sflow ¼ flow stress of the material
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