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University of Calgary
PRISM: University of Calgary's Digital Repository
Graduate Studies The Vault: Electronic Theses and Dissertations
2015-07-02
Statistical Analysis of Internal Corrosion of Sour Gas
Pipelines
Deng, Qiang (Charles)
Deng, Q. C. (2015). Statistical Analysis of Internal Corrosion of Sour Gas Pipelines (Unpublished
master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/27875
http://hdl.handle.net/11023/2329
master thesis
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UNIVERSITY OF CALGARY
Statistical Analysis of Internal Corrosion of Sour Gas Pipelines
by
Qiang (Charles) Deng
A THESIS
SUBMITTED TO THE FACULTY OF GRADUATE STUDIES
IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE
DEGREE OF MASTER OF ENGINEERING
GRADUATE PROGRAM IN MECHANICAL AND MANUFACTURING
ENGINEERING
CALGARY, ALBERTA
JUNE, 2015
© Qiang (Charles) Deng 2015
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Abstract
Gas gathering pipelines have played and will continue to play a critical role in safe,
reliable transportation of sour gas. Highly corrosive gases and unstable operating
conditions in gathering pipelines often contributes and results in serious internal
corrosion.
This study focuses on statistical analysis of the in-line inspection (ILI) data on sour gas
gathering pipelines to understand the parametric effects on internal corrosion of the
pipeline.
The ILI data showed that the bottom of the pipeline does not experience appreciable
corrosion. The serious corrosion was observed to always occur at the interface between
gas and liquid phases. Studies also showed that internal corrosion defects were more
likely to occur on the uphill segment of pipeline than the downhill segment.
Simulations of the flow patterns in the pipelines confirm that the uphill segment has the
slug flow pattern which is likely a key factor in causing internal corrosion.
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Acknowledgements
I would like to express my sincere gratitude to my supervisor, Dr. Frank Cheng for
his constant guidance, encouragement and support throughout my graduate studies
program. His deep love and perception of science, his persistent endeavour for searching
for the truth, and his consistent efforts at achieving perfection have always inspired and
helped me to carry out this project. From him, I have learned a lot, not only in the area of
my specialty, but also in the style of doing research.
Many thanks go to Dr. Luyao Xu, who gave me much support and many helpful
suggestions during my studies. Also many thanks go to Shell Canada Ltd for providing
the pipeline in-line inspection data for my study.
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Dedication
This work is dedicated to my wife Hua Zhang and my parents Guirong Gao &
Jinhuang Deng, for their incessant support. Also to my lovely daughters: Jiani, Anny and
Winny.
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Table of Contents
Abstract ............................................................................................................................... ii
Acknowledgements ............................................................................................................ iii
Dedication .......................................................................................................................... iv
Table of Contents ................................................................................................................ v
List of Tables ................................................................................................................... viii
List of Figures and Illustrations ......................................................................................... ix
List of Symbols, Abbreviations and Nomenclature ........................................................... xi
Chapter One: Introduction .................................................................................................. 1
1.1 Research background ................................................................................................ 1
1.2 Research objectives ................................................................................................... 2
1.3 Contents of thesis ...................................................................................................... 3
Chapter Two: Literature Review ........................................................................................ 4
2.1 Pipeline basics ........................................................................................................... 4
2.1.1 The importance of pipeline systems to oil and gas industry .............................. 4
2.1.2 Introduction of gathering, transmission and distribution pipelines ................... 6
2.1.3 Threats to pipeline integrity ............................................................................... 9
2.2 Sour gas pipelines ................................................................................................... 12
2.3 Internal corrosion in sour gas pipelines .................................................................. 13
2.3.1 Sour gas corrosion ........................................................................................... 14
2.3.2 Pitting corrosion ............................................................................................... 16
2.3.3 Vapor phase corrosion ..................................................................................... 17
2.3.4 Sulfide stress cracking (SSC) .......................................................................... 18
2.3.5 Hydrogen induced cracking (HIC) .................................................................. 20
2.3.6 Microbiologically influenced corrosion ........................................................... 21
2.4 Statistics of sour gas pipeline failure due to internal corrosion .............................. 23
2.5 Integrity management of internal corrosion of sour gas pipelines .......................... 26
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2.5.1 Integrity management requirement .................................................................. 26
2.5.2 Methods of integrity management ................................................................... 28
2.5.3 Corrosion mitigation strategies ........................................................................ 31
Chapter Three: Pipeline ILI Data Collection and Processing ........................................... 34
3.1 Pipeline information ................................................................................................ 34
3.2 ILI Data collection .................................................................................................. 35
3.2.1 Factors affecting the ILI data accuracy ............................................................ 35
3.2.2 Operation specifications................................................................................... 36
3.3 ILI data verification and processing ....................................................................... 37
3.4 Information of the inspected pipelines .................................................................... 38
Chapter Four: Non-uniform “Clock” Distributions of Internal Corrosion in Sour Gas
Pipelines ............................................................................................................................ 40
4.1 Results ..................................................................................................................... 40
4.1.1 Orientation of corrosion defects ...................................................................... 41
4.1.2 Relationship between corrosion depth and the orientation .............................. 44
4.1.3 Relationship between corrosion rate and the orientation ................................. 47
4.2 Discussion ............................................................................................................... 48
4.2.1 Distribution of corrosion defects inside the pipe ............................................. 48
4.2.2 Relationship between the corrosion depth and the orientation ........................ 50
4.2.3 Relationship between corrosion rate and orientation ....................................... 51
4.2.4 Effect of sediment on corrosion ....................................................................... 51
4.3 Summary ................................................................................................................. 53
Chapter Five: Effect of Pipeline Inclination (Altitude) on Internal Corrosion of Sour Gas
Pipeline ............................................................................................................................. 54
5.1 Fundamentals of fluid flow in pipelines ................................................................. 54
5.2 Relationship between corrosion and pipeline inclination ....................................... 59
5.3 Computer modelling of the fluid flow pattern ........................................................ 61
5.4 Discussion ............................................................................................................... 63
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5.5 Summary ................................................................................................................. 64
Chapter Six: Conclusions and Recommendations ............................................................ 65
6.1 Conclusions ............................................................................................................. 65
6.2 Recommendations ................................................................................................... 66
References ......................................................................................................................... 67
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List of Tables
Table 2.1 Threats to all pipelines [11]. ............................................................................. 11
Table 3.1. Summary of pipeline information [33] ............................................................ 34
Table 3.2 MFL 1.5 tool operating specifications [33] ...................................................... 36
Table 3.3 MFL 1.5 tool inspection specifications [33] ..................................................... 36
Table 3.4 MFL 1.5 tool inspection defect definitions [33] ............................................... 37
Table 4.1 Internal corrosion defects data .......................................................................... 41
Table 4.2 Internal corrosion rate of pipeline vs. the orientation of corrosion defects ...... 47
Table 5.1 Flow pattern along the pipeline from the simulation result .............................. 61
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List of Figures and Illustrations
Figure 2.1 Illustration of underground pipeline during construction. ................................. 5
Figure 2.2 Illustration of a completed aboveground pipeline. ............................................ 5
Figure 2.3 Oil and products pipeline system [5]. ................................................................ 8
Figure 2.4 Natural gas pipeline system [6]. ........................................................................ 9
Figure 2.5 Westcoast Energy Inc. Nig Creek pipeline accident [12]. ............................... 13
Figure 2.6 Illustration of pitting corrosion mechanism and resulting material
structures [15] ........................................................................................................... 16
Figure 2.7 Illustration of vapor phase corrosion [16] ....................................................... 18
Figure 2.8 Illustration of sulfide stress corrosion cracking [20] ....................................... 19
Figure 2.9 Illustration of HIC in steel pipeline walls [22] ................................................ 20
Figure 2.10 Illustration of microbiologically influenced corrosion on iron/steel
surfaces [23] .............................................................................................................. 21
Figure 2.11 Percentage of accidents by facility type, 2003–2012 [26] ............................ 23
Figure 2.12 Total sour gas pipeline incidents and sour gas pipeline incidents/1000km
[1] .............................................................................................................................. 24
Figure 2.13 Sour gas pipeline incidents by cause [1] ....................................................... 24
Figure 2.14 Sour gas pipeline failures by cause per year [27] .......................................... 25
Figure 2.15 Sour gas pipeline incidents by cause for all years combined [7] .................. 25
Figure 2.16 Illustration of multi-dataset in-line inspection tool ....................................... 28
Figure 2.17 Internal wall loss characteristic of internal corrosion [31] ............................ 33
Figure 3.1 Pipeline 06-15 to 03-22 elevation profile from Google map .......................... 39
Figure 4.1 Corrosion defects vs. Orientation in the sour gas pipeline. The two
horizontal red lines shows the range where majority of corrosion defects occur. .... 42
Figure 4.2 Percentage of the orientation of corrosion defects .......................................... 43
Figure 4.3 Internal corrosion distribution on orientation .................................................. 44
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Figure 4.4 Depth of corrosion defects vs. Orientation in the sour gas pipeline (2007) .... 45
Figure 4.5 Depth of corrosion defects vs. Orientation in the sour gas pipeline (2010) .... 46
Figure 4.6 Depth of corrosion defects vs. Orientation in the sour gas pipeline (2013) .... 46
Figure 4.7 Corrosion rate vs. Orientation ......................................................................... 48
Figure 4.8 Illustration of two-phase flow (Cross-section view) ....................................... 52
Figure 5.1 Multi-Phase Flow Pattern [41] ........................................................................ 57
Figure 5.2 Stratified flow in downhill pipe ....................................................................... 58
Figure 5.3 Profile of different regions of slug [42]. Bubbles in the figure are gases
trapped in the liquids. ................................................................................................ 58
Figure 5.4. Relationship between corrosion orientation (a) and pipeline inclination (b) . 60
Figure 5.5 Flow pattern from the pipeline simulation result ............................................ 62
Figure 5.6 Erosion vs. velocity from the pipeline simulation result ................................. 63
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List of Symbols, Abbreviations and Nomenclature
Symbol Definition
AER Alberta Energy Regulator
ASME American Society of Mechanical Engineering
bbl Barrel
CA Corrosion allowance
CAPP Canadian Association of Petroleum Producers
CH4 Methane
CO2 Carbone dioxide
CRA Corrosion resistant alloy
CSA Canadian standard association
Fe(OH)3 Iron (III) hydroxide
FeS Iron sulphide
GE General Electrical
GPS Global position system
HC Hydrocarbon
HCA High consequence area
H2CO3 Carbonic acid
HIC Hydrogen induced cracking
H2O Water
H2S Hydrogen sulphide
HSC Hydrogen stress cracking
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ILI In line inspection
IMU Inertial measurement unit
LDC Local Distribution Company
MFL Magnetic flux leakage
MIC Microbiologically influenced corrosion
mmscfd Million standard cubic feet per day
MOP Maximum operating pressure
MP Megapascal
NACE National Association of Corrosion Engineers
NDT Non-destructive testing
NEB National Energy Board
NGL Natural gas liquids
PHMSA Pipeline and Hazardous Materials Safety
Administration
PIMP Pipeline integrity management program
ppm partial per million
PWHT Post weld heat treatment
SCC Stress corrosion cracking
SG Sour gas
SMYS Specified Minimum Yield Strength
SOHIC Stress orientated hydrogen induced cracking
SRB Sulphur reducing bacteria
SSC Sulphide stress cracking
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SWC Stepwise cracking
UT Ultrasound
UTCD Ultrasonic crack detection
WT Wall thickness
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Chapter One: Introduction
1.1 Research background
The gathering pipelines have been the most important links between gas wells (wellhead)
and facilities for sour gas treatment (e.g., gas plants). Sour gas refers to the gas
containing over 1% of hydrogen sulphide (H2S) by volume. One of the most serious
problems caused by the sour gas streams is internal corrosion of pipelines, which can lead
to pipeline leakage and failure, loss of production, facility shutdown, and a possible
environmental disaster.
For a long time, corrosion has been the main cause of failures of sour gas gathering
pipelines. The CAPP (Canadian Association of Petroleum Producers) Pipeline Technical
Committee has compiled statistics for sour gas pipelines’ failures that, in 2008 alone,
internal corrosion was the cause of 26% of the 31 sour gas incidents [1]. Because of the
high corrosion failure rates, sour gas pipelines have been a ‘money-burning’ asset, as
these pipelines always require replacement, maintenance, and a great deal of engineering
hours spend on troubleshooting.
The sour gas gathering pipelines are corroded in an environment of high acid rating and
complex composition conditions. Multiple corrosive forms, such as uniform corrosion,
pitting corrosion, microbiologically influenced corrosion (MIC), etc., would be
encountered, and some corrosion would be happening in a combined processes. Due to
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the characteristics of the transported sour gas which contains H2S, CO2, water and
sediments, the sour corrosion of a pipeline is complex. Most studies have been conducted
in the lab to determine how the compositions affect the corrosion process, or how the
simulated flow patterns affect internal corrosion. It is important to develop models to
predict sour corrosion for improved integrity in the oil and gas industry. From the point
of view of industrial practice, the models should be based on analysis of field data.
Currently, there has been limited work compiling and analysing field data to understand
the sour corrosion process and governing patterns.
1.2 Research objectives
The overall objective of this research is to understand sour corrosion of pipelines based
on statistical analysis of the field data. It is anticipated that the analysis will lay a firm
foundation to develop a complete understanding of the governing pattern of sour
corrosion of pipelines.
Progress will be made in the following topics.
1. Evaluate the influence of internal corrosion defects on the wall of sour gas
pipelines.
2. Determine the factors that influence internal corrosion of sour gas pipelines.
3. Statistically analyze the governing pattern of internal corrosion of sour gas
pipelines.
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4. Discuss the ways to mitigate internal corrosion of sour gas pipelines.
1.3 Contents of thesis
The thesis contains six chapters, with Chapter One giving a brief introduction of the
research background and objectives.
Chapter Two reviews comprehensively the basics of corrosion of sour gas pipelines.
Chapter Three describes the basic information of the investigated sour gas pipeline and
the ILI data acquisition.
Chapter Four presents the research results of the distribution of internal corrosion on pipe
wall using the clock orientation method.
Chapter Five presents the research results of the effect of inclination (altitude) on internal
corrosion.
Finally, the conclusions of this research, along with the recommendations for the further
work, is given in Chapter Six.
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Chapter Two: Literature Review
2.1 Pipeline basics
2.1.1 The importance of pipeline systems to oil and gas industry
A pipeline is a long tubular conduit or series of pipes, with pumps ( or compressors) and
valves for flow control, used to transport crude oil, natural gas, diluted bitumen, etc.,
especially over great distances. More than 95% of pipelines are underground and located
in rural areas, as seen in Figure 2.1. There are also pipeline systems above ground (Figure
2.2).
Pipelines have the highest capacity, and are the safest and least environmentally
disruptive form of transportation for oil and gas [2]. Pipelines are more cost-effective
than the alternative transportation options such as rail or tanker truck [3]. Pipelines
require significantly less energy to operate than operating trucks or railways and leave a
much lower carbon footprint. Moreover, the pipeline industry has contributed to strong
national economies. They have been integrated into the components of national security
in most countries [4].
In Alberta, the limited pipeline routes have been a bottle-neck issue for oil and gas export
in recent years.
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Figure 2.1 Illustration of underground pipeline during construction.
Figure 2.2 Illustration of a completed aboveground pipeline.
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2.1.2 Introduction of gathering, transmission and distribution pipelines
There are three main categories of pipeline systems:
1. Gathering pipelines
Gathering pipelines are groups of smaller interconnected pipelines forming complex
networks with the purpose of gathering oil and gas products from wells and transporting
them to oil batteries or natural gas processing facilities. In this group, pipelines are
usually short - a couple of hundred metres to a few kilometres - with small diameters.
Sub-sea pipelines for collecting product from deep water production platforms are also
considered gathering systems. These lines transport natural gas, crude oil and
combinations of these products which are sometimes mixed with water; and natural gas
liquids (NGLs) such as ethane, propane and butane. Normally the line size varies
from 101.6 mm to 304.8 mm outside diameter (4 in. to 12 in.). In Alberta more than
250,000 kilometres of gathering pipelines are in operation.
A gathering system is used for untreated product transportation operating at low pressures.
The pipelines go through remote locations (low population density). Pipe size is small
and pipe wall is thick. The pipelines have short or limited life. They are easy and
relatively low cost to replace. Many kinds of pipeline materials have been used: carbon
steel, stainless steel, aluminium alloys, fibreglass (composite), plastic etc.
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2. Transmission Pipelines
Transmission pipelines are mainly long pipes with large diameters, moving products (oil,
gas, refined products) between cities, countries and even continents. These transportation
networks include compressor stations in gas lines or pump stations for crude and multi-
product pipelines. Transmission lines are the energy-highways. Natural gas transmission
lines typically carry only natural gas and NGLs. Crude oil transmission lines carry
different types of liquids including crude oil and refined petroleum products in batches.
Petroleum product lines also move liquids such as refined petroleum products and NGLs.
These pipelines typically range in size from 101.6 mm to 1,212 mm (4 in to 48 in.).
About half are 457.2 mm (18 in.) or larger, and about one third are 254 mm. (10 in.) or
smaller. There are approximately 115,000 kilometres of transmission lines in Canada.
Transmission systems are used for treated clean products transportation at high pressures
using large diameter and thin wall thickness pipes. The system usually uses steel pipes
with a combination of coating and cathodic protection to ensure a long life (100 years +).
This type of pipeline is used for long-distance transportation. The surrounding
environment varies with varied terrain (mountains, prairies, swamps, river crossings,
highway crossings, permafrost, and deserts).
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3. Distribution Pipelines
Distribution pipelines are composed of several interconnected pipelines with small
diameters, used to take the products to the final consumers. Feeder lines distribute gas to
homes and businesses downstream. Pipelines at terminals for distributing products to
tanks and storage facilities are included in this group. Distribution pipelines mainly focus
on natural gas consumptions. Local distribution companies (LDCs) operate natural gas
distribution lines. Natural gas moves along distribution pipelines to homes, businesses
and some industries. Most range in size from 12.7 mm to 152.4 mm outside diameter
(half an inch to 6 in.). There are about 450,000 kilometres of these lines in Canada.
Distribution systems are used for treated products with low pressures using small
diameter and thick wall thickness pipes. These systems use various materials and
typically have long lives.
Figure 2.3 Oil and products pipeline system [5].
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Figure 2.3 and Figure 2.4 shows the systems of gathering pipelines, transmission
pipelines and distribution pipelines for crude oil and natural gas, respectively.
Figure 2.4 Natural gas pipeline system [6].
2.1.3 Threats to pipeline integrity
Pipeline integrity threat refers to a condition or set of circumstances that, if not mitigated,
could cause a pipeline to fail. A key component in managing pipeline safety is threat
identification. Nine primary threat conditions are identified in industrial standard ASME
B31.8S [7], and include:
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1. Dependent Threats (threats tending to grow over time)
Internal Corrosion
External Corrosion
Stress Corrosion Cracking
2. Stable Threats (threats that do not grow over time; instead they tend to act when
influenced by another condition or failure mechanism)
Manufacturing
Fabrication/Construction
Equipment
3. Time-Independent Threats (not influenced by time)
Human Error
Excavation Damage
Earth Movement, Outside Force or Weather
For gathering pipelines, the time-dependent threats are mainly internal corrosion. Alberta
Energy Regulator (AER) reported that 49.5% of internal corrosion caused pipeline
failures in Alberta in the period of January 1990 to December 2012 [8]. For transmission
pipelines, the time-dependent threats are mainly external, including external corrosion
and stress corrosion cracking. U.S. PHMSA's report shows corrosion accounts for 23% of
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the number of significant incidents in gas transmission pipelines from 1991 to 2010,
which is the number one cause of significant incidents [9].
For gas distributions pipelines, the time-dependent threats are mainly excavation damage.
U.S. PHMSA's report shows corrosion accounts for only 3.9% of the significant incidents
in gas distributions pipelines from 1991 to 2010. Corrosion is the lowest breakdown
causing factor among the significant incidents [10].
Table 2.1 Threats to all pipelines [11].
Threat Name
Percentage of Significant
Pipeline Incident Between
1991 and 2010
Threat Category
External Corrosion 9.9 % Time-dependent
Internal Corrosion 12.9 % Time-dependent
Stress Corrosion
Cracking 1.0 %
Time-dependent
Manufacturing Defects 3.4 % Time-stable
Construction and
Fabrication Defects 3.3 %
Time-stable
Mechanical Damage 23.4 % Random
Equipment Failure 13.3 % Random
Incorrect Operations 1.8 % Random
Forces of Nature 11.8 % Random
Miscellaneous and
Unknown 18.9 %
Random
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Time-dependent threats are the main focus of the pipeline integrity management program.
Table 2.1 shows the statistics of various reasons causing pipeline failures [11]. As
indicated above, internal corrosion causes 12.9% of significant pipeline incidents.
2.2 Sour gas pipelines
Sour gas is natural gas that contains measurable amounts of H2S, usually greater than 10
mole/kmole (1%) of H2S by volume. It is a colourless, flammable gas that smells like
rotten eggs and is poisonous to humans and animals. In addition to being toxic, H2S in the
presence of water also damages piping and other equipment handling sour gas via sulfide
stress cracking (SSC). Sour gas accounts for approximately 22 per cent of all natural gas
in Alberta.
Sour gas contains H2S, CO2, corrosive materials and solid particles in the gas commodity.
To send the raw gas to the gas plant or battery, pipelines are used. Usually corrosion
resistant materials are used in the construction of these pipelines. This calls for specific
requirements in terms of steel manufacturing, materials selection and testing, as well as
strict code compliance in the design, fabrication and operation of these pipelines.
Sour gas pipelines usually fall into the category of oil field sour gas gathering pipelines.
Sour gas pipeline systems more often use small diameter, thick wall thickness, low
operating pressure and low grade steel pipe. The transported products usually contain
large amount of corrosive medium, like water, H2S, CO2, chlorides, debris and sands. The
operating conditions are also unstable and variable. Therefore, sour gas pipelines often
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suffer serious internal corrosion. In Alberta, some sour gas pipelines have ruptured due to
internal corrosion and, as a result, released H2S containing gas in the past years. Sour gas
pipeline leaks and explosion are known to cause serious adverse environmental effects.
Figure 2.5 Westcoast Energy Inc. Nig Creek pipeline accident [12].
Figure 2.5 shows the Nig Creek pipeline accident on 28 June 2012, when Westcoast
Energy Inc. owned 16-inch sour gas pipeline ruptured and ignition occurred.
Approximately 25 minutes later, the 6.625-inch Bonavista Energy Corporation pipeline,
located nearby in the same right-of-way, ruptured and the escaping sour gas also ignited.
2.3 Internal corrosion in sour gas pipelines
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2.3.1 Sour gas corrosion
Normally corrosion occurs due to anodic and cathodic reactions in certain conditions.
The simplest proposed mechanism for the anodic dissolution of iron under acidic
conditions proceeds by:
Fe → Fe2+
+ 2e-
Similarly, the cathodic reaction proceeds by:
O2 + 2H2O + 4e- → 4OH
-
2H+
+ 2e- → H2
In the presence of dissolved H2S in the environment, the anodic and cathodic reactions, as
well as chemical reactions can include [13]:
Fe → Fe2+
+ 2e-
Fe2+
+ HS- → [FeHS]
+
[FeHS]+
→ FeS + H+
2H+ + 2e
- → H2
2H2O + 2e- → H2 + 2OH
-
H2S → H+ + HS
-
HS- → H
+ + S
2-
2H2S + 2e- → H2 + 2HS
-
The corrosion rate of mild steel in H2S corrosion is affected by H2S gas concentration,
temperature, velocity, and the protectiveness of the scale [14].
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Generally, sour gas corrosion could be expected to occur when:
The H2S concentration in the gas phase is greater than 500 ppm (These limits are
supplied as a guideline only and may not be absolute)
H2S gas is dissolved in free water
Other failures due to environmental cracking such as SSC and hydrogen induced cracking
(HIC) also seriously affect sour gas pipeline safety. Chloride concentration also plays an
important role in the overall corrosion and under-deposit mechanisms. In respect to the
overall corrosion rate, chlorides increase the conductivity of the corrosive solution due to
a change in ionic strength, leading to an increase in the corrosion rate. In the under-
deposit corrosion mechanism, chlorides can promote the removal of protective scales (if
there are any), leading to localized attack.
Sulphur may be co-produced with sour gas. As a result of pressure and temperature
changes (in most cases a reduction) in the flowing conditions or in shut-in conditions,
sulphur may precipitate from polysulphides and cause plugging and/or corrosion
problems. From the corrosion viewpoint, sulphur can increase corrosion in many ways,
including compromising protective iron sulphide layers, enhancing cathodic reactions,
and impairing inhibitor performance.
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2.3.2 Pitting corrosion
Pitting corrosion along the bottom of the pipeline is the primary corrosion mechanism
leading to failures in sour gas pipelines. The common features of this mechanism are:
The presence of water containing H2S in combination with any of the following:
CO2, chlorides, elemental sulphur or solids.
Pipelines carrying higher levels of free-water production with no means of water
removal (i.e. no well site separation or dehydration).
The presence of fluid traps (i.e. low spots) where water and solids can accumulate
due to low gas velocity.
Figure 2.6 Illustration of pitting corrosion mechanism and resulting material
structures [15]
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Figure 2.6 shows the pitting corrosion process. When the metal (steel) surface is exposed
to an electrolyte, the anodic reaction starts on the metal surface [15]. The defected points
of the metal surface function as local anodes causing localized galvanic corrosion and
formation of initial pits. Localized stresses, in form of dislocations emerging on the
surface, may also become anodes and initiate pits [15]. This then grows to become a
rapid attack that results in massive damage of the metal. The oxidizing cation of iron
enables the formation of pitting even when there is no supply of oxygen in the metal
surface.
In wet gas gathering systems containing H2S & CO2, the initiation and growth of pitting
corrosion can be influenced by many variables. In sour systems, semi-protective iron
sulphide(s) scales will form. The scales are only protective in the absence of scale
disrupters, such as solids, chlorides, methanol, sulphur, high velocities, etc. Localized
breakdown of iron sulphide(s) scales typically result in accelerated pitting corrosion.
2.3.3 Vapor phase corrosion
Corrosive gasses in the vapor phase corrosion is a less common mechanism that can also
lead to pipeline failures. Vapor phase above sour fluids have been found to corrode steel
pipelines in an unsteady manner. The presence of liquid hydrocarbon lowers corrosion
rates, whereas oxygen contamination increased corrosion rates. High rates of
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Figure 2.7 Illustration of vapor phase corrosion [16]
methanol injection have been a known contributor to vapor phase corrosion in sour
systems. Although not specifically addressed in the practice, many of the preventative
measures will also mitigate this mechanism [17]. Figure 2.7 shows an illustration of the
vapor phase and how it contributes to corrosive attack in a gas pipeline with anti-
corrosion chemicals (corrosion inhibitor) injection. In sour gas pipelines, water saturated
gas also contains H2S.
2.3.4 Sulfide stress cracking (SSC)
The environmental cracking mechanisms, such as sulfide stress cracking (SSC), are also
associated with corrosive failure in sour gas pipelines. Figure 2.8 illustrates the SSC
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process. Steel reacts with hydrogen sulphide, forming iron sulphide and atomic hydrogen
as corrosion by-products [18]. Atomic hydrogen either combines to form H2 at the metal
surface, or diffuses into the metal matrix. The mechanical properties of steel are
diminished [18]. Thus, the corrosion process leads to pipeline SSC. Selection of materials
resistant to SSC and control of combined stress are considered the primary acceptable
means to prevent failures by this mechanism. NACE MR0175/ISO 15156 requires sour
service for equipment that comes in contact with H2S in oil and gas production
environment [19].
Figure 2.8 Illustration of sulfide stress corrosion cracking [20]
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2.3.5 Hydrogen induced cracking (HIC)
Figure 2.9 shows the mechanism of hydrogen induced cracking (HIC) in the sour gas
pipelines. The corrosive environment of sour gas causes chemical reactions generating
atomic hydrogen on the internal pipe wall [21]. The atomic hydrogen penetrates and
diffuses readily through a metallic structure [21]. When the crystal lattice is in contact or
is saturated with atomic hydrogen, they combine and form hydrogen molecules [21].
When the pressure of molecular hydrogen increases at levels sufficient to rupture the
metal, the mechanical properties of steel are diminished [21]. Thus the corrosion process
leads to pipeline hydrogen induced cracking.
Figure 2.9 Illustration of HIC in steel pipeline walls [22]
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Where considered necessary, specification and use of materials manufactured with
demonstrated HIC resistance is the preferred method of preventing failures by this
mechanism. However, many of the preventative measures have been studied which can
help mitigate failures by this mechanism.
SSC is a sulfide-induced HIC which processes or conditions involving wet hydrogen
sulfide, i.e. sour services.
2.3.6 Microbiologically influenced corrosion
Figure 2.10 Illustration of microbiologically influenced corrosion on iron/steel
surfaces [23]
Microbiological Influenced Corrosion (MIC) in sour gas systems is a factor of the sour
gas pipeline internal corrosion. MIC can greatly enhance corrosion rates, especially in
conjunction with solid deposition and the temperature range 15°C - 70°C is known to be
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associated with increased MIC activity, leading to localized attack [24]. Evidence of
bacteria has been reported in some sour gas failure investigations [25]. However there is
no industry consensus with regard to the overall contribution to this corrosion mechanism
[25].
Figure 2.10 shows the mechanism of MIC. Firstly, a deposit of biofilm forms Fe
oxidizing bacteria on the metal surface where there is a low velocity or stagnation of
water. With oxygen concentration cell forming, Fe2+
will be dissolved from metal
surface, which moves outward through the tubercle, oxidizing further to Fe3+
. Gallionella
(Fe oxidizing bacteria) assists in or promotes the formation of Fe(OH)3. Then Fe(OH)3,
slime and other bacterial species stay on the wall of tubercle. As tubercle matures,
slime/biomass begins to decompose, forming sulphates that attract SRB (sulphate
reducing bacteria), resulting in H2S production on the interior of the pipeline. FeS may be
formed during these reactions. Finally, if chlorides are present with the Gallionella, Fe
chlorides may form, which are highly acidic. In an extreme, unmonitored situation,
tubercles grow together, forming a coating with severe pitting underneath. Tuberculation
can result from non-biomass materials such as carbonates, silicates, phosphates, greases,
mud, and debris. The result is pitting or even crevice corrosion underneath [23].
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2.4 Statistics of sour gas pipeline failure due to internal corrosion
The statistics from Transportation Safety Board of Canada shows that the gathering lines
account for 12% of total accidents reported over the 10 year period (2003–2012) in the
pipeline industry in Canada as shown in the Figure 2.11[26].
From the statistics of Alberta Energy Regulatory (AER), sour gas pipeline systems
accounted for 3% of the total pipeline incidents in Alberta in 2008. Internal corrosion was
the cause of 26% of the 31 sour gas incidents in Alberta in 2008 as shown in Figure 2.12
and Figure 2.13 [1]. Internal corrosion is the leading cause of sour gas pipeline incidents.
Figure 2.11 Percentage of accidents by facility type, 2003–2012 [26]
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Figure 2.12 Total sour gas pipeline incidents and sour gas pipeline incidents/1000km
[1]
Figure 2.13 Sour gas pipeline incidents by cause [1]
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Figure 2.14 Sour gas pipeline failures by cause per year [27]
Figure 2.15 Sour gas pipeline incidents by cause for all years combined [7]
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The report of Pipeline Performance in Alberta 1990-2012 also indicated that internal
corrosion had been the primary cause of sour gas pipeline incidents in Alberta as shown
in Figure 2.14 and Figure 2.15.
2.5 Integrity management of internal corrosion of sour gas pipelines
2.5.1 Integrity management requirement
In Canada, should natural gas from a particular well have high sulphur and carbon
dioxide contents (sour gas), a specialized sour gas pipeline must be installed.
The Alberta Energy Regulator (AER) sets up regulations and rules to ensure the safety
methods are being fulfilled and complemented. The AER requires licensees to develop
and implement pipeline integrity management programs (PIMG) to identify and mitigate
risks associated with a particular pipeline, including corrosion mitigation and monitoring
as well as other risk factors. Licensees must be re-evaluated annually to assess corrosion
potential and to track actions taken to ensure compliance with all regulations, Alberta’s
Pipeline Act, Pipeline Regulation, and applicable Canadian Standards Association (CSA).
The results of the inspection or tests must be recorded and retained for a minimum of six
years [28]. National Energy Board Onshore Pipeline Regulations Clause 53 (1) requires
that a company shall conduct inspections on a regular basis and audits, with a maximum
interval of three years [29].
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In US, the Pipeline Safety Improvement Act of 2002 mandated that the U.S. Department
of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA),
issue regulations that require operators of natural gas transmission pipelines to develop
and implement Integrity Management Programs for pipelines in High Consequence Areas
(HCAs).
A critical aspect to pipeline operations that these regulations required is the recognition
of the importance of an internal corrosion monitoring program. Directive 66 cites specific
regulatory requirements detailed in the Alberta Pipeline Act and Regulation and the CSA
Z662 Standard, Oil and Gas Pipeline Systems [24]. The directive also includes the AER
Pipeline Inspectors' Guide to Corrosion Failure Procedures, which details the
requirements specific to follow-up of corrosion incidents. The AER developed this
section in consultation with industry pipeline corrosion specialists.
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2.5.2 Methods of integrity management
Figure 2.16 Illustration of multi-dataset in-line inspection tool
There are many methods of assessing the integrity of a pipeline. The ILI, as shown in
Figure 2.16, has enabled the timely detection, sizing, assessment, and consequent
mitigation of corrosion anomalies before they lead to pipeline failures. ILI tools are built
to travel inside a pipeline and collect data as they go. One of the most accurate methods
of metallic pipeline condition assessment is magnetic flux leakage (MFL) ILI using
advanced non-destructive electromagnetic methods to scan the full circumference and
length of the pipeline for damage by corrosion and other causes. Axial MFL ILI tools
were developed within the last 40 years to inspect pipelines that experienced the threat of
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corrosion. The MFL-ILIs detect and assess areas where the pipe wall may be damaged by
corrosion. The more advanced versions are referred to as "high-resolution" because they
have a large number of sensors. The high-resolution MFL-ILIs allow more reliable and
accurate identification of anomalies in a pipeline, thus, minimizing the need for
expensive verification excavations (i.e., digging up the pipe to verify what the problem
is).
Another commonly used ILI is ultrasound (UT) tools. It is also a non-destructive testing
(NDT) technology which has been applied for a variety of inspection tasks for many
years. A major advantage of ultrasound is the ability to provide quantitative
measurements. The ability to acquire quantitative measurements means that the actual
wall thickness of a pipe section can be determined with high accuracy and reliability.
There are different ways to determine thickness, such as using different types of
transducers and applying ultrasound techniques differently (for instance piezo-electric
transducers versus transducers based on electro-magnetic acoustic transmission). The
most widely used tools available from several vendors make use of piezo-electric
transducers. The type of transducer chosen (i.e. dynamic range, focal point etc.) and the
characteristics of the electronics used (i.e. pulse repetition frequency, sampling rate etc.)
have major influence on the detection threshold, the accuracy and depth and length
resolution [30].
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The MFL inspection can offset the limitations of UT inspection technology in detecting
small diameter corrosion pits. The limitation of the UT technology to see small diameter
corrosion pits can be seen by the number of false negatives on the y-axis of the unity plot.
The use of statistical analysis and reliability methods, supported by high-resolution ILI
data has become a common practice in making failure likelihood estimates for existing
pipelines in which such data exists [31]. As these methods intrinsically address variables
such as wall loss feature incidence rate, growth rate and size distributions, they can be
employed to make estimates of reliability and failure likelihood for both external
corrosion and internal corrosion.
Accurate assessment of pipeline anomalies can improve the decision making process
within a Pipeline Integrity Management Program (PIMP), and excavation programs can
then focus on required repairs instead of calibration or exploratory digs. After ILI
inspection, the collected data is downloaded and compiled so that an analyst is able to
accurately interpret the collected signals. Most pipeline inspection companies have
proprietary software designed to view their own tool's collected data. One example of the
use of ILI data analysis is fit-for-service assessment. The purpose of the fitness-for-
service assessments is to identify which features reported by the ILI would cause an
integrity concern at the pipeline’s pre-reduction maximum operating pressure (MOP).
Aged pipelines that contain corrosion, cracking, and deformation anomalies are
occasionally subject to pressure reductions to ensure safe operation. Pipelines are
required to be evaluated for a fitness-for-service assessment prior to a return to service at
the full operating pressure. Fit-for-service has to be evaluated based on anomalies
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reported by metal loss MFL, ultrasonic crack detection (UTCD), or geometric (caliper)
ILI surveys.
2.5.3 Corrosion mitigation strategies
If a failure indicates a corrosive condition, the operator must have a documented plan to
prevent further corrosion failures. This plan must consider other lines within the same
pipeline system and include details of the mitigation measures to be adopted. The
Pipeline Regulation, Sections 53 [32], requires the operator to maintain records of any
corrosion maintenance activities for at least six years. Typical mitigation and monitoring
measures for internal corrosion could include combinations of the following:
Corrosion coupons
Electronic monitoring devices
Inhibition (continuous and/or batch)
Lab analysis to determine failure cause
Pipeline cleaning by pigging or chemicals
Fluids analysis
Flow modeling
Adding anti-corrosion chemicals (corrosion inhibitors), or chemical substances that
decrease corrosion rates, is one of the most effective methods to control internal
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corrosion of pipelines. However, no single inhibitor suits all situations, which creates a
challenge for industry when it comes to selecting the best product for the job.
Many studies have been made on the internal corrosion for the gas transmission pipeline.
When evaluating the internal corrosion susceptibility, one of the simplest methods to
perform screening is to view orientation charts for internal wall loss features. Where
water drop-out and accumulation is an essential aspect of the internal corrosion
mechanism that is associated with the product and flow characteristics being considered,
wall loss that is associated with internal corrosion should be expected at the bottom of the
pipe, i.e., 180 degree of defect orientation in Figure 2.17. This is especially true where
concentrations of internal wall loss can be seen to coincide with steeper pipeline
inclination angles or receipt points. [31]
To date, there has been limited reporting on analysis of ILI data to understand the internal
corrosion of sour gas pipelines. This is attributed to the complicated effects of H2S and
CO2 in the gas composition on the corrosion mechanisms and the various operating
conditions. At the same time, the lab testing conditions are not representative of field
conditions, and thus, the results cannot be used directly for corrosion assessment. The
internal corrosion of sour gas pipeline remains an interesting, but challenging topic to
both the research community and to industry.
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Figure 2.17 Internal wall loss characteristic of internal corrosion [31]
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Chapter Three: Pipeline ILI Data Collection and Processing
3.1 Pipeline information
The pipeline data selected for this study was from the Shell Pipeline ILI reports [33 - 35].
The pipeline is a typical sour gas gathering line. The basic information of the pipeline is
listed in Table 3.1 [33].
Table 3.1. Summary of pipeline information [33]
Client Shell Canada Limited
License/Line #: 24240 - 10
Location Butcher Canyon
Rout 06-15-004-01 W5M to 03-22-004-01 W5M
Product (Substance) SG
Year Built 1989
MOP 9930 kPag (1440 psig)
Length 1.1 kms
Pipe Diameter (Outside) 168.3 mm (6.63”)
Pipe Wall Thickness(S) 5.56 mm (0.22”)
Pipe Specification (SMYS) 290 MPa
Seam Seamless
This pipeline is injected with anti-corrosion chemicals (corrosion inhibitors) and
methanol (for preventing hydrate formation) during operations.
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3.2 ILI Data collection
In this study there were three sets of pipeline ILI data which were collected in 2007, 2010
and 2013 on Shell Canada Ltd.’s Butcher CSM to Jct. pipeline. GE Oil & Gas PII
Pipeline Solutions conducted the inspections and evaluations based on GE pipeline
inspection procedures and standards. The inspection tool is MFL 1.5 tool.
3.2.1 Factors affecting the ILI data accuracy
The geometry of metal loss defects, running speed of the tools, and debris in the pipeline
can affect the accuracy of MFL inspection results. The tool speed is a critical factor in the
measurement of metal loss defects. When an MFL 1.5 tool runs at speeds outside of its
specification, the accuracy of the metal loss measurements taken in these areas is
degraded. In the worst case, the tool over-speed can result in data loss due to over
sampling; and the tool under-speed can result in excessive noise in the data. Both of these
conditions can cause defects to be mis-measured by the tool [33].
Deposits of debris in pipelines can result in grading discrepancies. For example, iron
sulphide pit-filling can cause defect under sizing due to its magnetic permeability. Wax
and other debris types can prevent the sensors from riding firmly against the interior pipe
wall. In the worst cases, they can prevent the tool from sampling data [33].
Small diameter defects such as corrosion pits add a volumetric error and have a tendency
to be under-graded. Very large areas of general corrosion can also prove problematic for
MFL 1.5 tool technology. The sizing accuracy of such defects may be degraded. [33]
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3.2.2 Operation specifications
1. GE Oil & Gas PII Pipeline Solutions MFL 1.5 Operating Specifications:
Table 3.2 MFL 1.5 tool operating specifications [33]
Operating Specifications Tolerances
Pipeline Temperature Up to 80 Celsius (176 Fahrenheit)
Pipeline Pressure Up to 137 bar (2000 psi)
Optimum Tool Speed 1.6 km/hr – 11.0 km/hr (1.0 mph – 6.8 mph)
Media Liquid or Gas
The operating specifications of MFL 1.5 tool, including pipeline temperature, pressure,
speed and media, are listed in Table 3.2.
2. GE Oil & Gas PII Pipeline Solutions MFL 1.5 inspection specifications:
Table 3.3 MFL 1.5 tool inspection specifications [33]
Specifications Seam Welded Seamless
Pitting General
Corrosion
Pitting General
Corrosion Defect Area 2Tx2T → 4Tx4T ≥ 4T x 4T 2Tx2T → 4Tx4T ≥ 4T x 4T
Minimum Reported Depth
10% 20% 20% 25%
Depth Accuracy @ 80%
Confidence
±10% ±20% ±20% ±25%
Length Accuracy @ 80%
±13 mm / 0.5" ±25 mm / 1.0" ±19 mm / 0.75" ±25 mm / 1.0"
Confidence Width Accuracy
@ 80% Confidence
±25 mm / 1.0" ±25 mm / 1.0" ±32 mm / 1.25" ±32 mm / 1.25
Axial Location Accuracy
±1%
Orientation Accuracy ±30 degrees
* +/- % represents absolute measurement –> actual defect depth- graded defect depth
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Table 3.3 gives the definition of the measurement for each item, like defect area,
minimum reported depth, accuracy, etc.
3. Defect definitions:
Table 3.4 MFL 1.5 tool inspection defect definitions [33]
Defect Definitions Length Width
Pitting 2T - 4T 2T- 2T
General Corrosion 4T - 10T 4T - 10T
* ‘T’ denotes wall thickness
Table 3.4 gives the definition of defect for pitting and general corrosion. In addition to
metal loss defects, the MFL 1.5 tools detect metallurgical anomalies encountered in the
pipe wall, mechanical distortion of the pipe wall, and excess metal in close proximity to
the pipe. Every effort has been made to identify and label all hardware such as valves,
flanges, taps, anchors, clamps, patches and sleeves. Manufacturing irregularities such as
laminations, carbon impregnations, hard spots and inclusions are detected by the tools.
When suspected anomalies due to manufacturing defects are found, the report comments
should note “Possible Mill Defect”. GE Oil & Gas PII Pipeline Solutions reports metal
loss data up to 70%. After 70% depth, the metal loss is classified as 70%++. This is due
to saturation level of the MFL 1.5 signal beyond 70% wall loss [33].
3.3 ILI data verification and processing
After the ILI data were collected from the field, there was a data verification procedure to
ensure the data are accurate and justified. This can reduce the errors and promote the
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efficiency. This process is completed before the report is issued. A set of internal
corrosion defects data was screened and collected. This report analysis was conducted
based on three internal corrosion data.
3.4 Information of the inspected pipelines
Figure 3.1 shows the elevation profile of the inspected pipeline. There is a creek in the
middle of the pipeline route. The pipeline route goes uphill and then downhill to the low
point of the creek bottom. It then goes up to the highest point of the pipeline, and then
goes down to the junction point. The total length of the pipeline is 1.1 km with an
elevation change of 33.5 m. This is a typical sour gas gathering pipeline route in Alberta.
The uphill and downhill elevation difference causes varying flow patterns which affect
the internal corrosion of the pipeline.
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Figure 3.1 Pipeline 06-15 to 03-22 elevation profile from Google map
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Chapter Four: Non-uniform “Clock” Distributions of Internal
Corrosion in Sour Gas Pipelines
In this chapter, the internal corrosion of sour gas pipelines was analyzed to determine the
distribution of corrosion defects inside the pipe.
4.1 Results
Analysis of internal corrosion defects has been made based on the three sets of ILI data
collected from the pipeline inspection reports. Table 4.1 shows the statistics of corrosion
defects and their orientations inside the pipe. It is noted that there is no relationship
between the defect number and the inspection years, i.e., the defect number was assigned
randomly in each year. Moreover, this data was summarized from the ILI report database
which includes both external corrosion and internal corrosion data. However, only the
internal corrosion is affected by the transported medium. In order to distinguish the
distribution of the corrosion defects, a clock number is used to indicate the location of the
defect along the pipe. The distance in the table refers to the length that the MFL smart pig
travelled from the pig launcher to the point where internal corrosion defect was detected
on the pipe wall of the sour gas pipeline. The analysis results are included in the
following sections.
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4.1.1 Orientation of corrosion defects
Table 4.1 Internal corrosion defects data
Defect
No.*
Absolute Distance
(m)
Wall Loss
(%)
Orientation
(position on
the clock)
2007
9 700.97 27 5:30
10 701.1 56 5:30
11 701.26 32 6:00
13 731.38 34 5:30
14 732.03 25 6:30
15 801.47 19 10:15
16 835.12 29 6:45
23 1066.33 23 8:00
2010
1 5.97 10 4:45
6 164.92 20 5:30
9 227.39 23 6:45
10 230.6 21 5:00
11 230.73 21 5:30
12 231.44 32 6:45
14 256.7 23 6:00
15 259.86 20 6:45
17 306.5 24 4:30
18 306.6 28 1:45
19 500.23 27 5:00
24 702.1 51 5:30
25 702.38 28 5:30
28 733.24 27 6:00
31 836.46 31 6:00
2013
8 227.49 22 6:45
14 702.19 46 5:00
15 702.47 28 5:00
18 733.27 20 6:30
21 836.51 20 6:15
23 849.57 39 5:45
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* Note: Defect No. is consistent with the ILI Inspection report. It is a pipeline defect label
of both the internal corrosion and the external corrosion.
Figure 4.1 shows the orientation of corrosion defects detected by ILI in the pipelines. It is
seen that the majority of corrosion defects occur between 5:00 - 7:00 o’clock. Moreover,
the corrosion defects are not evenly distributed along the pipeline. At some segments, the
corrosion defects are scattered; and at other segments, there is no corrosion defect
detected.
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
0 200 400 600 800 1000 1200
Ori
enta
tion (
O'c
lock
)
Distance (m)
Figure 4.1 Corrosion defects vs. Orientation in the sour gas pipeline. The two
horizontal red lines shows the range where majority of corrosion defects occur.
Figure 4.2 shows the percentage of the orientation of corrosion. The main results include:
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a) Corrosion defects between 1:00 ~2:00 and 10:00 ~ 11:00 o’clock: 2 points, 6.9% of
all points;
b) Corrosion defects between 4:00 ~5:00 and 7:00 ~ 8:00 o’clock: 3 points, 10.3% of all
points;
c) Corrosion defects between 5:00 ~7:00 o’clock: 24 points, 82.8% of all points;
Overall, there are 93% of internal corrosion defects occurring along the bottom section
(4:00-8:00 o’clock) of the pipe, and only 7 % of corrosion defects occur along the top
section (8:00-3:00 o’clock).
0.00
20.00
40.00
60.00
80.00
100.00
0:00 ~ 1:00
& 11:00 ~
12:00
1:00 ~ 2:00
& 10:00 ~
11:00
2:00 ~ 3:00
& 9:00 ~
10:00
3:00 ~ 4:00
& 8:00 ~
9:00
4:00 ~ 5:00
& 7:00 ~
8:00
5:00 ~ 6:00
6:00 ~ 7:00
Per
centa
ge
(%)
Orientation ( O'Clock)
Figure 4.2 Percentage of the orientation of corrosion defects
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There is a trend between the corrosion susceptibility and the orientation in the vapour
phase as shown in Figure 4.3. Diamond data points represent analyzed ILI data and the
solid curve is a fit to the gas phase dot. The susceptibility of orientation is symmetry with
12 o'clock and 6 o'clock as the axis. As the orientation is closer to the gas/liquid interface,
the corrosion susceptibility will increase.
0
2
4
6
8
10
12
14
Co
rro
sio
n F
req
uen
cy
Orientation (O'clock)
Corrosion in gas phase
Corrosion in liquid phase
Fitting-gas phase
4:00&8:00 4:30&7:30 4:45&7:15 5:00&7:00 5:15&6:45 5:30&6:30 5:45&6:15 6:00
Gas phase
Liquid
phase
Figure 4.3 Internal corrosion distribution on orientation
4.1.2 Relationship between corrosion depth and the orientation
Figure 4.4 – 4.6 show the relationship between the depth of corrosion defects and their
orientations. There is a trend between the corrosion depth and orientation from the 2007
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data as shown in Figure 4.4. The depth of corrosion defects increases as the corrosion
defect is approaching to the gas/liquid interface (5 o’clock and 7 o’clock). It can be seen
that the highest depth of corrosion defect is around 5 o’clock. The lowest depth of
corrosion defect is around 10 o’clock. For Figure 4.5 and 4.6, the trend is not obvious
because the corrosion defects are all close to the gas/liquid interface. The "special point"
identified in Figure 4.5 requires additional investigation.
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
0 0.2 0.4 0.6 0.8 1 1.2
Ori
enta
tati
on (
O'c
lock
)
Corrosion Depth (mm)
Figure 4.4 Depth of corrosion defects vs. Orientation in the sour gas pipeline (2007)
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0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
0 0.2 0.4 0.6 0.8 1 1.2
Ori
enta
tati
on (
O'c
lock
)
Corrosion Depth (mm)
Special point
Figure 4.5 Depth of corrosion defects vs. Orientation in the sour gas pipeline (2010)
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
0 0.2 0.4 0.6 0.8 1 1.2
Corrosion Depth (mm)
Ori
enta
tion (
O'c
lock
)
Figure 4.6 Depth of corrosion defects vs. Orientation in the sour gas pipeline (2013)
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4.1.3 Relationship between corrosion rate and the orientation
Table 4.2 Internal corrosion rate of pipeline vs. the orientation of corrosion defects
Orientation Corrosion Rate (mm/year)
2007 Inspection 2010 Inspection 2013 Inspection
5:00 N/A N/A N/A
5:15 N/A N/A N/A
5:30 0.17 0.17 N/A
5:45 0.15 N/A 0.15
6:00 0.04 0.04 N/A
6:15 0.06 N/A 0.06
6:30 N/A N/A N/A
6:45 N/A N/A N/A
7:00 N/A N/A N/A
Table 4.2 shows the internal corrosion rate of pipelines as a function of the orientation of
corrosion defects. All the corrosion rates were calculated from the ILI data obtained on
the same pipeline over years. Data was screened and selected to have a minimum of two
calculated corrosion rates for different year periods at the same corrosion spot. It can be
seen that the corrosion rate is identical for the same spot but different year periods.
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0
0.02
0.04
0.06
0.08
0.1
0.12
0.14
0.16
0.18
0.2
0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00
Co
rro
sio
n R
ate
(m
m/y
r)
Orientation (O'Clock)
Corrosion Rate 2007
Corrosion Rate 2010
Corrosion Rate 2013
Figure 4.7 Corrosion rate vs. Orientation
Figure 4.7 shows the internal corrosion rate plotted with the orientation of the corrosion
defects on the pipe. It is seen that the highest corrosion rate is found between the 5:00 and
6:00 o’clock positions of the pipe. The corrosion rate is about 0.18 mm/year.
4.2 Discussion
4.2.1 Distribution of corrosion defects inside the pipe
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Sour gas gathering pipelines transport produced gas from the wellhead, and the gas fluid
contains impurities such as water, H2S, CO2 and sands, sometimes hydrocarbon (HC)
liquids as well.
Matin [17] found that the magnitude of corrosion was influenced by the quantity of water
condensed on the metal surface. The periodicity of rise and falls in corrosion rate also
appeared to be influenced by the liquid level.
The water (or HC liquids)/gas interface inside a pipe divide the pipe into two spaces: gas
phase and water (liquids) phase. In the gas phase, H2S and CO2 are heavier than CH4, and
are more likely staying at the lower part of the gas space. On the internal pipe surface,
when the inhibitor film or scale is broken caused by the slug flow pattern in the multi-
phase flow, the corrosion defect will be formed. At the gas/liquids interface, the H2S (and
CO2) content reaches its peak. The result in Figure 4.1 shows the most corrosion defects
around the orientations of 5:00 ~ 7:00 o'clock, where the liquid-gas interface exists.
Moreover, around the liquid/gas interface, dissolved acid gases like H2S and CO2, lower
the pH of water due to dissolved H2S in the water, causing the liquids to have high
corrosivity.
At the bottom of the pipe, the chance of exposure of steel surface to the corrosive
environment is not the highest because there are solid deposits covering the pipe surface.
Therefore, the corrosion defects at 6:00 o'clock are not the worst points.
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4.2.2 Relationship between the corrosion depth and the orientation
The depth of the corrosion defects reflects the real corrosion rate. The bigger depth of
corrosion defect, the higher the corrosion rate is. The corrosion rate is affected by
temperature, pH value, oxygen level and fluid velocity. The following discussion will
highlight the correlation between increasing corrosion rates and corrosion orientation
approaching the gas and liquid interface.
As stated in Section 4.2.1, in the gas phase, H2S and CO2 highly affect the corrosivity of
the environment. It can be deduced that the closer to the gas/liquid interface, the higher
corrosivity is [36]. Normally, a higher corrosive environment will result in a higher
corrosion rate [36]. Another factor that may have much effect on the corrosion rate is
temperature. A sour gas pipeline is buried underground. There is a temperature gradient
around the pipe wall. On the top of the pipe, the temperature is the lowest and the bottom
is the highest. The temperature is increasing while the corrosion defect orientation is
approaching the gas/liquid interface. Higher temperature can result in a higher corrosion
rate.
Moreover, the oxygen level also has an effect on the corrosion rate of the defect. The sour
gas pipeline has been injected with anti-corrosion chemicals and methanol during normal
operation. Oxygen can be dissolved into the chemicals and methanol, and be brought into
the pipeline with the injection. These chemicals and methanol can be condensed on the
pipe wall and accumulated on the bottom of the pipe. The highest oxygen levels are
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found around the gas/liquid interface along the pipe wall. The pipe top will have the
lowest level of oxygen. High oxygen levels will lead to higher corrosion rate.
Normally sour gas pipelines are designed under a certain flow rate to avoid the erosion
corrosion. So the fluid velocity will have very little effect on the corrosion rate.
4.2.3 Relationship between corrosion rate and orientation
Section 4.2.2 has discussed the factors that can affect the corrosion rate. The corrosion
rate follows the same trend as the relationship between the corrosion depth and the
orientation. Generally, the corrosion rates are supposed to vary with changes in H2S and
CO2 contents, gas flow rate, operating pressure, operating temperature, and seasonal
ambient temperature changes. However, Table 4.2 shows that the corrosion rates are not
affected by these factors on the same spot (orientation). The possible reason may be that
the corrosivity formed by H2S on different orientation is the dominated factor. The
phenomenon needs to be investigated by having more data from various sour gas
pipelines to conduct more statistical analysis.
4.2.4 Effect of sediment on corrosion
In sour gas pipeline operations, the solid sediment can have two possible effects on the
internal corrosion. One effect is the occurrence of localized pitting corrosion under the
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sediment. Bacteria may be present in the biofilm formed under sediment, and contribute
to pit formation and growth. This could be occurring inside the sour gas pipelines. On the
other hand, the sediment could isolate the pipe wall from the sour gas corrosive
environment. This helps the prevention of corrosion. In this work, the majority of
corrosion defects are found at the boundary between the gas-liquid interface, rather than
the bottom of the pipe. Part of the reason can be attributed to the protective role of solid
deposits at the pipe bottom, as illustrated in Figure 4.8.
Figure 4.8 Illustration of two-phase flow (Cross-section view)
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4.3 Summary
In the sour gas gathering pipelines, the transported fluids contain varied ratios of water
and hydrocarbon liquids, and corrosive gases such as CO2 and H2S. The most serious
corrosion defects are located close to the gas/liquids interface, i.e., 5:00 and 7:00 o'clock
positions. The bottom (6:00 o’clock or 180 degree angle) is not the worst area for internal
corrosion.
The corrosion depth in the sour gas pipeline varies with the defect orientation. The most
serious corrosion depths are also located close to the gas/liquids interface, i.e., 5:00 and
7:00 o'clock positions. The least serious corrosion depths are closest to the top of the pipe.
The corrosion depth of the defect on the bottom is not the biggest.
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Chapter Five: Effect of Pipeline Inclination (Altitude) on Internal
Corrosion of Sour Gas Pipeline
This chapter analyzes the relationship between the internal corrosion, i.e., susceptibility
of occurrence, and the inclination of the pipeline based on the available ILI data sets. In
particular, the pipe inclination, also called elevation or altitude, is the deviation or amount
of deviation in the vertical direction, classified herein as uphill or downhill.
5.1 Fundamentals of fluid flow in pipelines
Multiphase flow is a common occurrence in sour gas gathering pipelines. Internal
corrosion caused by multiphase flow in these lines and the technical challenges involved
in their corrosion inhibition are also well known [37]. Proper understanding of the
underlying mechanisms governing corrosion in multiphase flow is helpful to the
implementation of a pipeline integrity management program. Implementation of an
effective inhibition program is necessary for safe and profitable operation of existing
pipelines and the development of new fields.
Multiphase flow involves the simultaneous flow of more than one phase within a pipe.
This includes two-phase hydrocarbon liquids/gas and hydrocarbon liquids/water flows
and three-phase hydrocarbon liquid/water/gas flows. Several flow patterns exist in
multiphase flows. It must be noted that the flow is seldom homogeneous and, in most
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cases, different velocity and phase fractions exist at any given location within the pipe.
This is fundamentally different from single-phase flow. Also, in most cases, the flow is
turbulent [38]. Figure 5.1 shows the multi-phase flow pattern.
At low gas and liquid velocities, a stratified layer of liquid flows under the gas, the
interface between the two layers is smooth. At higher gas velocities, the front of the plug
begins to overrun the liquid film and assimilates it in the process. This regime is called
slug flow and is the most important flow regime from a corrosion point. It is noted that a
separate water layer is always present at the bottom of the pipe in all the flow regimes.
This layer exists even at water cuts as low as 10% and measurable corrosion can occur in
multiphase flow [39].
Stratified flow is a multi-phase flow in which the flow in many fluids varies with density
and depends upon the gravity. Due to which the fluid with lower density is always above
the fluid with higher density. It is stratified flow that is most likely to occur in downhill
two-phase flow, see Figure 5.2.
Slug flow exists in pipelines carrying hydrocarbon liquids and gas when high production
of hydrocarbon liquids and gas is required. Slug flow is characterized by the appearance
of intermittent liquid slugs that propagate through the pipe. An idealized slug unit is
shown in Figure 5.3 and consists of four zones. Ahead of the slug is a slow moving liquid
film, with gas flowing above it. Waves are formed on this film and grow to bridge the
pipe. They are then accelerated to the gas velocity and form the slug. The front of the
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slug overruns the slow moving film ahead of it and assimilates it into a mixing zone
behind the front, creating a highly turbulent region. This highly turbulent mixing zone
entrains gas, which is passed back into the slug body. Here the turbulence is reduced, and
eventually the liquid velocity is reduced to a point where it is no longer able to sustain the
bridging of the pipe. This is the tail of the slug. Liquid is shed from the tail of the slug to
a trailing film. This liquid in turn mixes with more incoming liquid to form a film on
which the next slug will propagate [40].
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Figure 5.1 Multi-Phase Flow Pattern [41]
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Figure 5.2 Stratified flow in downhill pipe
Figure 5.3 Profile of different regions of slug [42]. Bubbles in the figure are gases
trapped in the liquids.
Gas
Liquid
Flow direction
Flow direction
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5.2 Relationship between corrosion and pipeline inclination
A corrosion orientation vs. distance plot (a) and a pipeline inclination vs. distance plot (b)
are plotted together in Fig. 5.4 in order to determine the relationship between pipeline
corrosion and elevation. It can be observed that the majority of corrosion defects are
found in the range of uphill segment of the pipeline. There is a smaller probability for pits
to be found on the downhill pipeline segment. On the transition from uphill to downhill
segments, no corrosion defects were identified. However, the transitions from downhill to
uphill segments can often have corrosion defects, resulting from the accumulation of
water locally. At the same time, the anti-corrosion chemicals would also remain locally
for corrosion prevention. Thus, there is no obvious corrosion detected in areas of the
pipeline where the height transitions from downhill flow to uphill flow in this work.
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0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
0 200 400 600 800 1000 1200
Ori
enta
tion (
O'c
lock
)
Distance (m)
(a)
1540
1550
1560
1570
1580
1590
0 200 400 600 800 1000 1200
Ele
vat
ion (
m)
Distance (m)
(b)
Figure 5.4. Relationship between corrosion orientation (a) and pipeline inclination
(b)
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5.3 Computer modelling of the fluid flow pattern
To figure out how the fluid flow patterns affect the internal corrosion in each segment of
the pipeline, the fluid mechanics simulation was conducted using Aspen HYSYS V8.4
software. The simulation data were used with different periods of operations. This
software provides HYSYS-OLGA dynamic simulation for the multiphase flow behavior.
Table 5.1 summarizes the result of flow pattern from the simulation. Flow patterns varied
with slug flow and two-phase flow in Table 5.1.
Figures 5.5 shows the results of the fluid flow distribution along the pipeline base on
Table 5.1. It is shown that the slug flow occurs at the uphill segments, and a stable phase
flow occurs in the downhill segments. Since over 90% of the internal corrosion occurs on
the uphill segments, it is thus assumed that the corrosion is somewhat correlated to the
slug flow generated in the segments.
Table 5.1 Flow pattern along the pipeline from the simulation result
Pipeline Segment
Number
Pipeline Segment Position Flow Pattern
1 Position 0 To 354.7 m Slug Flow
2 Position 354.7 m To 639.0 m Stable Two-phase Flow
3 Position 639.0 m To 713.5 m Slug Flow
4 Position 713.5 m To 852.7 m Stable Two-phase Flow
5 Position 852.7 m To 889.5 m Slug Flow
6 Position 889.5 m To 4094 m Stable Two-phase Flow
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Figure 5.6 shows the threshold fluid flow velocity for erosion to occur and the flow
velocity in the pipeline investigated. Since the flow velocity is much lower than the
threshold velocity to cause erosion, there is no erosion concern in the internal corrosion
of the pipeline.
1540
1550
1560
1570
1580
1590
0 200 400 600 800 1000 1200
Ele
vat
ion (
m)
Distance (m)
Figure 5.5 Flow pattern from the pipeline simulation result
Slug Flow
Stable 2-phase Flow
Slug Flow
Stable 2-phase Flow
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0
5
10
15
20
25
30
35
0 200 400 600 800 1000 1200
Vel
oci
ty (
m/s
)
Pipe length (m)
Flow velocity
Erosion velocity
Figure 5.6 Erosion vs. velocity from the pipeline simulation result
5.4 Discussion
The multiphase flow is more likely to propagate an internal corrosion issue on the
uphill segments of the pipeline, as shown in Figure 5.1, because the slug flow regime
contributes to the corrosion likely significantly by stagnating fluid flow around the slug.
The flow patterns from the simulation results explain the uphill corrosion phenomenon
based on the slug flow characteristics and the effect on corrosion.
The hydrocarbons coming from the reservoirs in pipelines form a multiphase complex
mixture (gas, liquids and solids) with different flow patterns that, due to highly turbulent
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hydrodynamics, can cause erosion and corrosion. Slug flow is one of these high turbulent
flow patterns [43]. This flow is characterized by a turbulent front, a liquid film and a gas
phase package that travels above the film. The slug front is considered to be highly
turbulent due to the mixture of liquid, gas and solid phase that, in turn, can produce
erosion/corrosion on the pipeline surface. [43]
The addition of solids to an aqueous phase with H2S and CO2 under slug flow operation
results in an increase of the corrosion rate. The action of abrasive solids, even at low
concentrations such as the one used in this study, are likely to promote protective film
removal and therefore cause an increase in corrosion rates [44].
Field data suggests that for horizontal pipelines, the slug frequency is usually in the range
of 1 to 20 slugs/minute depending on the liquid velocity. However, if the pipe is inclined,
the slug frequency can increase to values much greater than these. This may lead to
higher levels of corrosion [45].
5.5 Summary
In the multi-phase flow sour gas pipelines, the uphill segments have the highest
possibility of internal corrosion. The downhill segments of pipeline have the least internal
corrosion. The transitions between downhill and uphill segments of pipelines may not be
the corrosion point.
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Chapter Six: Conclusions and Recommendations
6.1 Conclusions
In this research, the internal corrosion of sour gas pipelines was studied using a statistical
analysis method based on industrial ILI datasets provided. Main conclusions are drawn as
follows.
The internal corrosion has a higher possibility to occur on the lower portion on the pipe
than the top portion. Specially, previous study found that corrosion is the most serious at
the gas/liquids interface [17].
Figure 5.2 showed that the internal corrosion has a higher possibility on the uphill
segment of pipelines than the downhill segment.
The transitions from uphill to downhill segments experience no corrosion, while the
transitions from downhill to uphill segments does not find obvious corrosion. This is
probably related to the accumulation of corrosion inhibitor locally.
During internal corrosion of sour gas pipelines, the fluid flow pattern plays a key role.
The internal corrosion of sour gas pipelines is dominated by the slug flow pattern. The
concluded corrosion statistics is primarily related to the flow pattern based on
simulations.
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6.2 Recommendations
1. When designing sour gas pipelines, a greater allowance for wall thinning from
internal corrosion (thicker wall thickness) should be designed in uphill portions of
the pipeline compared to downhill portions.
2. When conducting an in-line inspection on a sour gas pipeline, greater care and
time should be taken when inspecting lower bottom (b/w 4 o'clock and 8 o'clock)
of the pipeline for the internal corrosion, perhaps more sensor on the bottom of
the ILI than top.
3. When conducting an in-line inspection on a sour gas pipeline, more attention
should be paid on the uphill portion of the pipeline than the downhill portion.
4. Try to minimize elevation differences of the pipeline when selecting the pipeline
route to minimize the uphill segments of the sour gas pipeline.
5. Further study may be conducted on the relationship between the H2S content and
the corrosion rate in the sour gas pipeline.
6. The effects of anti-corrosion chemicals on the corrosion rate should be considered
and studied further.
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