Corrosion under Insulation on Offshore Facilities

by

MIGUEL LAMSAKI

Submitted

in partial fulfillment of the requirements

for the degree of

MASTER OF ENGINEERING

Major Subject: Petroleum Engineering

at

DALHOUSIE UNIVERSITY

FACULTY OF ENGINEERING

Halifax, Nova Scotia September, 2007

© Copyright by Miguel Lamsaki, 2007

ii

Dalhousie University Faculty of Engineering

Process Engineering and Applied Science

The undersigned hereby certify that they have examined, and recommend to the Faculty of Graduate studies for acceptance, the project entitled “Corrosion under Insulation on Offshore Facilities” by Miguel Lamsaki in partial fulfillment of the requirements for the degree of Master of Engineering.

Dated: Supervisor:

Georges J. Kipouros Co- supervisor: George Jarjoura Examiners: Stuart Pinks P. Carey Ryan

iii

Dalhousie University

Faculty of Engineering

DATE:

AUTHOR: Miguel Lamsaki.

TITLE: Corrosion under Insulation on Offshore Facilities

MAJOR SUBJECT: Petroleum Engineering

DEGREE: Master of Engineering

CONVOCATION: October, 2007

Permission is herewith granted to Dalhousie University to circulate and to have for non-commercial purpose, at its discretion, the above project upon request of individuals or institutions.

Signature of Author

The author reserves others publication rights and neither the project nor extensive extracts from it may printed or otherwise reproduced without the author’s written permission. The author attests that permission has been obtained for the use of any copyrighted material appearing in this project (other than brief excerpts requiring only proper acknowledgement in scholarly writing), and that all such use is clearly acknowledged.

iv

TABLE OF CONTENTS

LIST OF TABLES viii

LIST OF FIGURES ix

LIST OF ABBREVIATIONS AND SYMBOLS xi

ACKNOWLEDGEMENTS xii

ABSTRACT xiii

1. INTRODUCTION 1

1.1 BRACKGROUND 1

1.2 CORROSION MECHANISM 3

1.3 TYPES OF CORROSION 7

1.3.1 Uniform Attack 8

1.3.2 Pitting 9

1.3.3 Crevice Corrosion 12

1.3.4 Stress Corrosion Cracking 14

1.3.5 Hydrogen Damage 17

1.3.6 Intergranular Corrosion 18

1.3.7 Galvanic Corrosion 20

1.3.8 Selective Leaching 21

1.4 SCOPE OF THE PROJECT 23

2. INSULATION SYSTEMS 24

2.1 HEAT TRANSFER PROPERTIES 26

2.1.1 Conduction 27

2.1.2 Convection 28

2.1.3 Radiation 28

2.2 THERMAL PROPERTIES 29

2.2.1 Thermal Conductivity 29

v

2.2.2 Thermal Conductance 30

2.2.3 Thermal Transmittance 30

2.2.4 Thermal Resistance 30

2.3 MECHANICAL AND CHEMICAL PROPERTIES 31

2.3.1 Density 32

2.3.2 Moisture Resistance 32

2.3.3 Compressive Strength 33

2.3.4 Thermal Use Range 34

2.3.5 Fireproofing 35

2.3.6 Sound Attenuation 36

2.3.7 Chemical Neutrality 36

2.3.8 Other Properties 37

2.4 INSULATION MATERIALS 40

2.4.1 Calcium Silicate 40

2.4.2 Expanded Perlite 41

2.4.3 Glass and Mineral Fibers 41

2.4.4 Cellular Glass 42

2.4.5 Polyurethane and Polyisocyanurate Foams 43

2.4.6 Elastomeric Foams 43

2.4.7 Aerogels 44

2.5 PROTECTIVE COVERINGS AND FINISHES 44

2.5.1 Adhesives 45

2.5.2 Cements 45

2.5.3 Coatings and Mastics 45

2.5.4 Sealants and Caulks 46

2.5.5 Jacketing Systems 47

2.5.5.1 Aluminum Jackets 48

2.5.5.2 Stainless Steel Jackets 49

2.5.5.3 Plastic Jackets 49

vi

2.5.5.4 All Service Jackets 49

2.6 ISULATION FAILURE MECHANISM 50

3. OIL AND GAS OFFSHORE STRUCTURES 55

3.1 TOPSIDE FACILITIES 61

3.1.1 Processing Systems 62

3.1.2 Storage Systems 64

3.1.3 Piping Systems 66

3.2 INDUSTRY TREND 69

4. CORROSION UNDER INSULATION 71

4.1 CORROSION UNDER INSULATION MECHANISM 72

4.2 FACTORS PROMOTING CORROSION UNDER INSULATION 75

4.2.1 Marine Environment 75

4.2.2 Air Pollutants 77

4.2.3 pH Effect 80

4.2.4 Environmental Conditions 83

4.2.5 Service Temperature 84

4.2.6 Insulation Materials 87

4.2.7 Mechanical Design of Equipment and Insulation Installation 88

4.2.8 Mechanical Damage 89

4.3 SUSCEPTIBLE PLACES 91

4.4 INSPECTION METHODS 92

4.4.1 Pulsed Eddy Current Testing 94

4.4.2 Real Time Radiography 94

4.4.3 Magnetostrictive Technology 95

4.4.4 Infrared System 97

4.4.5 Neutron Backscatter 97

4.4.6 Long Range Ultrasonic 98

vii

4.5 RISK BASED INSPECTIONS 98

4.6 INDUSTRY TREND 100

5. PROTECTIVE COATINGS 104

5.1 PAINT COATINGS 105

5.2 METALLIC COATINGS 108

5.3 SURFACE PREPARATION 110

5.4 FAILURE MECHANISM 111

5.5. INDUSTRY TREND 112

6. CASE STUDIES 114

6.1 INDUSTRY TREND 121

7. DISCUSSION 122

8. CONCLUSIONS 134

9. RECOMMENDATIONS 137

10. REFERENCES 140

11. APPENDICES 146

viii

LIST OF TABLES

Table 1.1 Standard Potential Series of Metals 5

Table 1.2 Acceptable Corrosion Rates of Ferrous and Nickel Based Alloys 7

Table 1.3 Effect of Alloying on Pitting Resistance of Stainless Steel Alloys 11

Table 1.4 Common Metal- Environment Combinations Leading to Stress Corrosion Cracking 16

Table 2.1 Moisture Resistance Property of Various Insulation Materials 33

Table 2.2 Compressive Strength of Different Insulation Materials 34

Table 2.3 Recommended Thermal Temperatures by Du Pont Company 35

Table 4.1 Major Ions in Solution in an Open Sea Water at S°/00 = 35.0 77

Table 5.1 Paint Coating Application Coverage Rate 107

Table 6.1 Results of the Corrosion Test 117

Table 6.2 Occurrence of Stress Corrosion Cracking on coiled 304 spring Specimens in Boling Saturated Sodium Chloride Solution at 108◦C 119

Table 6.3 Occurrence of Stress Corrosion Cracking on coiled 304 spring Specimens in Boling Saturated Calcium Chloride Solution at 138◦C 120

Appendix A - Basic Types of Insulation for Low Temperatures 147

Appendix B - Basic Types of Insulation for Intermediate Temperatures 148

Appendix C - Basic Types of Insulation for High Temperatures 149

Appendix D – Protective Coverings and Finishes 150

ix

LIST OF FIGURES

Figure 1.1 Basic Corrosion Cell 4

Figure 1.2 Uniform Attack in an Insulated Pipe 9

Figure 1.3 Random Pitting 10

Figure 1.4 Crevice Corrosion of an Area of a Teflon Washer on a 316 Stainless Steel Plate 14

Figure 1.5 Cross Section of a 304 Stainless Steel Pipe Showing Stress Corrosion Cracking 15

Figure 1.6 Hydrogen Damage on a Steel Pipe 17

Figure 1.7 Intergranular Corrosion in a Fireplug Component 19

Figure 1.8 Galvanic Corrosion between a Carbon Steel Pipe and a Brass Valve 20

Figure 1.9 Removal of Zinc from a Brass Pipe Due to Selective Leaching Process 22

Figure 2.1 Heat Transfer Modes 27

Figure 2.2 Effect of pH on Corrosion Rate of Iron in Aerated Water 37

Figure 2.3 Typical Vessel Insulation Using Rigid Blocks 38

Figure 2.4 Typical Pre-Formed Pipe Insulation Multilayer Construction 39

Figure 2.5 Removable and Reusable Insulation System 40

Figure 2.6 Typical Insulation System Where Compounds Are Used 46

Figure 2.7 Rubberized Asphalt Vapor Barrier Membrane on an Ammonia System 47

Figure 2.8 Aluminum Jackets Secured with Screws 48

Figure 2.9 Improper Finishing of Jacketing System 51

Figure 2.10 Improper Sealing of an Insulation End Section 52

Figure 2.11 Lower Section of an Aluminum Jacketing System Installed Over the Upper Section 53

Figure 2.12 Aluminum Jacket Laps Installed Near the Top Section of Piping 53

Figure 2.13 Typical Vessel Attachments Where Water May Bypass Insulation 54

Figure 3.1 Areas of Corrosion and Types of Corrosion Control for Offshore Structures 57

Figure 3.2 Hibernia Gravity Base Structure 59

x

Figure 3.3 The Thebaud Facility 60

Figure 3.4 Floating Production, Storage and Offloading Vessel 61

Figure 3.5 Application of Rigid Cellar Glass Blocks on a Storage Tank 65

Figure 3.6 Corrosion Above an Insulation Support Ring 65

Figure 3.7 Schematic Representation of a Typical Christmas Tree System 67

Figure 3.8 Potential Places Where Water May Bypass Insulation on Piping 68

Figure 3.9 Insulation Jacket Open at Vertical Beam 69

Figure 4.1 Corrosion Under Insulation Near the Bottom Part of a Carbon steel Storage Tank 73

Figure 4.2 Metal Loss of Carbon Steel in Three Different Environments 76

Figure 4.3 Canadian SO2 Emissions from Acid Rain Sources, 1980 – 2004 79

Figure 4.4 Effect of pH on Corrosion of Iron in Aerated water at Room Temperature 80

Figure 4.5 Five Year Mean pH of Acid Rain in Canada and United Sates 82

Figure 4.6 Effect of Temperature on Carbon Steel Corrosion in Water 86

Figure 4.7 Unsealed Insulation Penetrations Where Water Can enter the Insulation 89

Figure 4.8 Mechanical Damage of Jacketing Systems 90

Figure 4.9 Real Time Radiography System 95

Figure 4.10 Schematic Diagram of Magnetostrictive Technology 96

Figure 5.1 Schematic Representation of Sacrificial Zinc Coating over Steel Surface at a Void 109

Figure 6.1 Carbon Steel Pipe and Insulation Samples Installed on the Pipe 115

Appendix E – Typical Oil and Associated Gas Production Process 151

Appendix F – Typical Gas Production Process 152

xi

LIST OF ABBREVIATIONS AND SYMBOLS

ASJ = All Service Jackets

API = American Petroleum Institute

CCPUF = Closed Cell Polyurethane Foam

g = Grams

FPSO = Floating Production Storage and Offloading

GBS = Gravity Base Structure

kg = Kilograms

kPa= Kilo Pascal

m2 = Metre Square

mm = Millimetres

mm/yr = Millimetres per year

MPa = Mega Pascal

NACE = National Association of Corrosion Engineers

NDT = Nondestructive Testing

OCPUF = Open Cell Polyurethane Foam

PIF = Polyisocyanurate Foam

PP = Polypropylene

PU = Polyurethane

RBI = Risk based inspections

VIP = Vacuum Insulation Panel

W/m x◦C = Watts per metre degree Celsius

xii

ACKNOWLEDGEMENTS

I would like to express my sincere appreciation and special thanks to the members of the

thesis supervisory committee, Dr Georges J. Kipouros, Professor, Department of Process

Engineering and Applied Science; Dr George Jarjoura, Professor, Department of Mining

and Metallurgical Engineering; Mr. Carey Ryan, Vice President, Petroleum Research

Atlantic Canada (PRAC); and Mr. Stuart Pinks, Manager, Health, Safety and

Environment, Canada – Nova Scotia Offshore Petroleum Board (CNSOPB) for their

invaluable guidance, support and outstanding contribution throughout the course of this

research project and for making possible the realization and culmination of this study. I

would also like to thank all the staff of Petroleum Research Atlantic Canada for providing

me the opportunity to work in their facilities.

I would like to acknowledge the effort of Mr. Stuart Pinks and Mr. Carey Ryan who

made possible the communication and interaction with staff members from the offshore

industry, who as well provided their personal experiences and comments about the

problem of corrosion under insulation on offshore facilities.

Finally, special thanks to my beloved wife, Ana Santana; my father, Miguel N. Lamsaki;

my mother, Ana Lamsaki; my twin, Sergio Lamsaki; my sister, Irene Lamsaki; and my

friends, Luis Perez and Geronimo Bendito for their patient and support throughout the

period of the Master program.

xiii

ABSTRACT

This thesis provides a comprehensive study of the problem of corrosion under insulation on offshore facilities. It also studies whether the actual characteristics of the environment of the east coast of Canada have an important effect on the occurrence of corrosion beneath insulation. Additionally, there is a review of the capabilities and limitations of the latest nondestructive evaluation techniques commonly used to inspect for corrosion on insulated systems together with the identification of opportunities for new or for improvements to existing inspection techniques.

Corrosion under insulation is and has been a major problem for the oil and gas industry for more than 50 years. It is difficult to identify because it remains hidden beneath the insulation hardware, frequently until unexpected failures occur. Corrosion under insulation can take place under any class of insulating material. Intruding water is the principal problem. Special consideration must be given to equipment design in order to avoid irregular shapes that are difficult to insulate and may be, in the long term, source of water intrusion. Systems with multiple protrusions through the insulation are more likely to allow water to diffuse into the insulation because sealants and caulking compounds used to seal joints and protrusion tend to get damaged quickly. In general, the insulation material that holds the least quantity of water, such as closed cell cellular glass insulation, should be used from the initial design phase of any offshore facility in order to prevent corrosion of the underlying metal surface.

Carbon steel and austenitic stainless steel are the two main materials commonly used for offshore applications. However, during the last few years the oil and gas industry is using more duplex stainless steel and super austenitic stainless steel alloys due to their improved corrosion resistant properties. Carbon steel is more likely to suffer uniform corrosion or pitting corrosion under insulation systems while austenitic stainless steel is subjected to stress corrosion cracking and highly localized pitting corrosion. Corrosion rates under insulation depend upon two factors besides the presence of moistures and water. First, warm and hot temperatures, usually the temperature range of -4°C to 150°C will have an important impact on corrosion under insulation and second, external and internal water contaminants such as chlorides and sulphides that may decrease the pH of water below 4.0 where corrosion rates are more likely to increase dramatically. In this case, since the north Atlantic region of Canada is presenting pH levels of rain and coastal fog near 4.0, special consideration should be given to insulation systems used on the existing offshore facilities.

In conclusion, preventing corrosion beneath insulation can be achieved with the right selection of insulation material, proper installation and effective application of risk based inspection programs together with the use of combined nondestructive examination techniques such as long range ultrasonic and magnetostrictive technology. However, there is the need to overcome their limited use on straight runs of pipes. It is also required to review the corrosion resistant properties of the new generation of alloys under severe conditions and under different types of coating and insulation systems to establish the temperature limits at which corrosion is more likely to occur and also to identify the more suitable protective coating to be used under insulation systems.

1. INTRODUCTION

1.1 Background

Since the first mobile offshore platform was used to drill a well 12 miles from the

Louisiana shore in the Gulf of Mexico in 1947, the continental shelf areas of the ocean,

like the Scotian and Jean d’ Arc Basins located in the north Atlantic region, now supply

approximately 25 % of the world total oil and gas production. Additionally, there will be

new exploration and production developments in deeper ocean basin areas combined with

a general production decline of onshore oil and gas reservoirs that will result in a

continuous growth of offshore hydrocarbon production [1].

According to the study of the world offshore oil and gas production forecast

2007-2011 published by Douglas and Westwood in April 2007, offshore oil production

has risen by over a third since 1991 and is forecast to continue to rise at about the same

rate by the year 2011 [2]. Simultaneously to this increment, the industry has faced a

variety of technical issues like corrosion under insulation that affects the performance and

the integrity of the offshore facilities.

A study prepared by Exxon Mobile Chemical and presented to the European

Federation of Corrosion in September 2003 indicated that:

• The main cause of leaks in the chemical and refining industries is due to corrosion

under insulation.

• 81 percent of piping leaks happened in pipes with a nominal diameter smaller

than 4 inch.

• More than 40 percent of piping maintenance cost is associated to corrosion under

insulation [3].

2

Experience has revealed that as time passes, jackets lose their capacity to protect

the insulation from the atmospheric conditions and thereby insulation gets wet. Water,

oxygen, and other corrosive contaminants will be able to reach the insulated metal and

therefore severe corrosion may occur [4].

One of the principal chemical manufacturing companies in the world, E.I. DuPont

de Numours and Company calculated that the direct cost associated with corrosion under

insulation can go beyond $10 million per year without including preventative

maintenance costs and indirect costs [3].

The proper design and selection of coating systems that are applied to piping and

vessels prior to installing the insulation have been major components in controlling

corrosion under insulation. Another factor that has been an important element for the oil

and gas industry in preventing and controlling corrosion problems is the development of

timely and reliable inspection techniques to detect corrosion under insulation and to

detect deterioration to insulation and associated sealing materials.

The aim of the corrosion engineer is to slow the corrosion process with the

application of cost effective corrosion monitoring and maintenance programs throughout

the useful life of the offshore structure. Usually corrosion losses are divided into two

categories: direct and indirect economic losses. Direct losses consist of costs related to

the cost of parts and labor to replace corroded metal. Indirect losses are associated with

plant shutdowns, loss of product and environmental damage [5].

At the present time, corrosion under insulation represents an important problem

for the oil and gas industry. Detection and prevention of corrosion under insulation can

represent a significant portion of the operating cost of a project; therefore it must be

carefully studied in order to maintain effectively and efficiently the offshore facilities

during their planned life cycle.

3

1.2 Corrosion Mechanism

Corrosion is the natural process of deterioration or destruction of a material due to

a chemical or electrochemical reaction with its environment [4]. Basically all

environments are corrosive. The most common corrosive environments are: air and

moisture; fresh and salt water; gases such as sulfur dioxide, chlorine and hydrogen sulfide

[6]. Corrosion of iron can be explained as an electrochemical process. The following

reaction describes the corrosion process of iron when is immersed in oxygenated water

[5]:

2 Fe 2 Fe++ + 4 e- anodic reaction (1)

O2 + 2 H2O + 4 e- 4 OH- cathodic reaction (2)

The overall reaction:

2 Fe + O2 + 2 H2O 2 Fe++ + 4 OH- 2 Fe (OH)2 (3)

Corrosion is a major concern when metals are used. The native state of metal is

the oxidized state. When metals are mined and refined, their original energy level is

increased. In the existence of oxygen and moisture, processed metal will instantly start

the process to return to its lowest level of energy [5]. The accumulated energy throughout

the refining process is released when metals convert to corrosion products [6].

During the corrosion process, the cathodic and anodic reactions occur

simultaneously; therefore it is possible to control corrosion by slowing down the rates of

either reaction [6]. One of the methods to reduce the rates of the anodic and cathodic

reactions is by the application of protective coating materials over the metal surface.

Protective coatings control the access of moisture and oxygen to the metal surface,

therefore corrosion rates are reduced.

4

The corrosion mechanism can be illustrated with the basic corrosion cell shown in

figure 1.1. It is composed of four elements: an anode, a cathode, an electrical path and an

electrolyte. The anode and cathode could be the same metal but different regions. In

offshore facilities the electrolyte is water in some form; a thin film of water is sufficient

to create the electrolyte in a corrosion cell. The electrical path could be a steel pipe or any

steel equipment that connects the anode with the cathode. Corrosion will not occur with

the absence of any of the four components [4].

Figure 1.1: Basic corrosion cell [7]

Normally the corrosion cell is known as the cathode, anode and the electrolyte.

The anode is the region of the metal surface that deteriorates and produces electrons. The

anode reaction is also called oxidation which means loss of electrons [8]. The cathode is

the section of the metal that does not corrode and consumes electrons produced at the

anode [4].

5

During the corrosion process, electrons flow from the anode region to the cathode

region. The driving force that allows the electrical current to flow is the energy that is

accumulated in the metal, also known as the potential of the metal. Each metal has

different corrosion resistant characteristics due to the amount of energy that is required

during its refining process, therefore every type of metal has a different tendency to

deteriorate. Table 1.1 shows the standard potential of metals compared to the standard

hydrogen electrode whose potential is zero [4].

Table 1.1: Standard potential series of metals [4]

Energy Required for Refining Metal Volts Tendency to Corrode

Most energy required Magnesium -2.37 Greatest tendency

Aluminum -1.66

Zinc -0.76

Iron -0.44

Tin -0.14

Lead -0.13

Hydrogen 0.00

Copper 0.34 to 0.52

Silver 0.80

Platinum 1.20

Least energy required Gold 1.50 to 1.68 Least tendency

The offshore environment is considered by many as the most severe of the

environments. In the oil and gas industry the most common metals are carbon steel and

stainless steel, therefore the hundreds of offshore platforms and drilling rigs operating

around the world are affected by the extreme corrosive marine conditions. This

6

unavoidable factor associated directly with offshore activities often leads to costly and

extensive maintenance and repair programs.

The common expression to describe the capacity of corrosion resistance of metals

and nonmetals in different environments is the corrosion rate. Corrosion rates are

expressed in different ways such as: grams per square inch per hour, milligrams per

square centimeter per day and percent weight loss. Another expression widely used by

engineers and scientist to express the corrosion rate is millimeters and micrometers per

year. The following formula is used to calculate the corrosion rate from the weight loss of

metals during a corrosion test [6]:

mm = 87.6 x W (millimeters per year) (4) Yr D x A x T

Where:

87.6 = conversion factor from centimeters per hour to millimeters per year

W = weight loss, mg

D = density of specimen, g/cm3

A = area of specimen, cm2

T = exposure time, hr

Another useful way to measure the extent of corrosion of almost any form of

corrosion except stress corrosion cracking is the depth of penetration, especially if the

attack is localized. The penetration refers to the depth of the deepest pit found on the

corroded area [8]. Many factors determine the corrosion rate of pipes, vessels and

different equipment on offshore platforms and rigs. Some examples of these factors are:

the conductivity of the electrolyte, the pH of water, dissolved gases, temperature and air

pollution [4]. Table 1.2 shows reference values commonly used to describe the metals

corrosion resistance property [6].

7

Table 1.2: Acceptable corrosion rates of ferrous and nickel based alloys [6]

Corrosion Rate (mm/yr) Relative Corrosion Resistance*

< 0.02 Outstanding

0.02 – 0.1 Excellent

0.1- 0.5 Good

0.5 – 1 Fair

1 – 5 Poor

>5 Unacceptable

*Based on typical ferrous and nickel based alloys

Covered areas as the case of an insulated pipe, where moisture and dust become

trapped, will have a higher rate of corrosion than uncovered areas. Conductivity of the

electrolyte is directly proportional to the rate of corrosion. Sodium chloride dissolved in

sea water increases the conductivity of the electrolyte and therefore increases the rate of

corrosion [9]. Another factor that can affect the corrosion rate is the solubility of

corrosion product. Usually when the corrosion product dissolves into the electrolyte, the

conductivity is increased and the corrosion rate will rise [10].

1.3 Types of Corrosion

Corroded metal appears in numerous forms depending on the corrosive

environment, the type of the metal, the nature of the corrosion product, the stress on the

metal and other variables. Corrosion is usually classified by the appearances on the

attacked metal [6]. Different types of corrosion have similar characteristics and therefore

can be classified into specific groups. Some of these types involve mechanisms that have

common characteristics that may contribute to the initiation of a specific class of

8

corrosion [10]. Every form of corrosion can be recognized by simple visual observation

and some of them can be identified just with the naked eye. The solution of a corrosion

problem can be achieved by cautious examination of the corroded equipment [6]. Eight

forms of corrosion are usually categorized by corrosion scientists and engineers and they

can be found on offshore insulated equipments. These types of corrosion are defined as:

uniform or general attack, crevice corrosion, pitting, intergranular corrosion, selective

leaching, galvanic corrosion, stress corrosion cracking and hydrogen damage [10].

1.3.1Uniform Attack

Uniform attack or generalized corrosion is a homogeneous chemical or

electrochemical reaction over a large area of a metal, characterized by uniform thinning

that proceeds without appreciable localized attack [6]. Uniform attack is the most

common type of corrosion, but at the same time the least risky [8]. From a technical

perspective, it is the form of deterioration that has the greatest damage of metal on a

tonnage basis [6]. Figure 1.2 shows an example of uniform attack on an insulated pipe.

9

Figure 1.2: Uniform attack in an insulated pipe [11]

Carbon steels and copper alloys under the effect of atmospheric conditions are

good examples of materials that usually show signs of general attack, while materials,

such as stainless steels or nickel chromium alloys, are usually affected with localized

attack [10]. During the general corrosion process, the corroding metal acts at the same

time as the anode and the cathode. With uniform corrosion the engineer is able to

calculate the life of the equipment and thereby can program inspections and replacements

on a regular schedule [6].

1.3.2 Pitting

Pitting corrosion is known as the deterioration of metals at localized areas rather

than over its whole surface. The corrosion reaction is concentrated at the localized areas

where the corrosion rate will be greater than the average corrosion rate over the entire

surface [4]. Figure 1.3 shows a deteriorated steel pipe due to pitting corrosion.

10

Figure 1.3: Random pitting [11]

Usually, the word pit is used to express any mark on the surface of metals that has

a shape of a hole. Crevice corrosion, galvanic corrosion, failure of a metal coating, or

corrosion by water droplets are some of the factors that may give rise to the initiation of

pits. The way it manifests on the corroded metal is with the development of sharply

defined cavities. The holes could be large and shallow or deep and narrow, but usually

they are reasonably small. Depending on the characteristics of the corrosive environment

they may be almost completely round or elliptic or have irregular shape [4].

Pits are sometime apart from each other over the surface of metals or sometimes

they are close together and they look like an irregular surface [6]. Pits typically grow in

the direction of gravity. Pitting corrosion is not restricted to carbon steels; it may also

occur in diverse metals used in offshore facilities. From a practical point of view,

11

chloride solutions generally promote the occurrence of pitting [8]. Stainless steels used in

offshore facilities are very susceptible to this type of corrosion due to seawater and its

chloride content that induces the occurrence of pitting [6].

In general the stainless steels are more vulnerable to be attacked and deteriorated

by pitting corrosion than any other type of metals or alloys. A variety of alloy studies

have been done to improve the pitting resistance of stainless steels. The results are

summarized in Table 1.3 [6].

Table 1.3: Effects of alloying on pitting resistance of stainless steel alloys [6]

Element Effect on Pitting Resistance

Chromium Increases

Nickel Increases

Molybdenum Increases

Silicon Decreases; increases when present with molybdenum

Titanium and

Columbium

Decreases resistance in FeCl3; other media no effect

Sulfur and Selenium Decreases

Carbon Decreases

Nitrogen Increases

Pitting is one of the most dangerous forms of corrosion. It causes unexpected

failure by deep perforations with only a small percent of weight loss of the metal. Pits are

difficult to detect by simple visual examination, especially when they are very small and

covered with corrosion products that frequently mask them [10].

Sometimes this type of corrosion requires a long time before pits become visible

on the metal surface. The time to form could range from months to years depending on

12

the corrosive environment and the type of metal. Pitting can be much more serious than

uniform corrosion, because sometimes they occur after an unpredictable period of time

when the attacked area is penetrated in a very short time and failure occurs with extreme

suddenness [6].

Additionally, pitting is complicated to predict by laboratory test and also difficult

to measure quantitatively, because under identical conditions a variety of pits with

different depths may occur. A method of measuring pitting intensity is with the ratio of

the deepest metal penetration at the deteriorated area to the average metal penetration

obtained by the general weight loss. Another method is to calculate a “pitting rate

equivalent”, that measures the deepest pit and the exposure time during the lab test

converted to an annual penetration rate [4]. When pits are not many and are widely

separated and at the same time there is not general corrosion attacking the metal, there is

a high ratio of cathode to anode area. As a result the penetration rate is greater than when

pits are many and closer together [10].

1.3.3 Crevice Corrosion

Crevice corrosion is an intense localized corrosion caused by a concentration cell

in which some corrosive agent is depleted inside the crevice. Corrosion in crevices can be

reduced by a good design of the equipment. Many different sites in offshore equipment

that are covered with insulation materials may give rise to this type of localized corrosion

if moisture or water penetrates through the insulation and reach the metal surface. The

crevice can be produced in four different ways [8]:

1. Cracks, seams, or metallurgical defects could act as sites for corrosion initiation.

2. A gap between metal contacting another metal that could allow moisture to enter, such

as in the threads of nuts and bolts or between lapped joints.

13

3. Deposits over the metal surface, such as precipitated salts, dirt, corrosion product or

dust.

4. Metal contacting porous nonmetallic material, such as gaskets, insulation materials or

porous paint [8].

Usually, during the corrosion process, the crevice deteriorates evenly just as the

metal outside the crevice does [8]. Because crevice corrosion is found very often in metal

components, it is normally considered a form of corrosion by itself. Nearly all metals and

alloys are vulnerable to this type of attack [12].

In the presence of seawater, the deterioration of copper and its alloys at crevices

occurs outside of the crevice rather than within. In the case of stainless steel alloys the

deterioration occurs within crevices. In general, metals that are resistant to general

corrosion are susceptible to develop crevice corrosion [10]. Figure 1.4 shows an example

of crevice corrosion on a stainless steel plate.

14

Figure 1.4: Crevice corrosion at the location of a Teflon washer on a 316L

stainless steel plate [13]

Stainless steels are vulnerable to this type of corrosion because they become

anodic within the crevice and cathodic outside it, developing a large ratio of cathode and

anode area, resulting in an intense localized corrosion attack. Crevice corrosion often

causes the development of stress corrosion cracking or corrosion fatigue [8].

1.3.4 Stress Corrosion Cracking

Stress corrosion cracking manifests itself with fine fractures that penetrate deeply

through the metal, caused by the existence of tensile stress or plastic strain and a

corrosive solution. If tensile stress or plastic strain does not exist, the metal would not

corrode in a cracking way [6]. Usually during stress corrosion cracking, metal loss is

normally very low, while cracks penetrate into the metal. The cracks may be

15

intergranular or transgranular, but always perpendicular to the highest stresses [4]. Figure

1.5 shows a stainless steel cross section that suffered stress corrosion cracking.

Figure 1.5: Cross section through 304 stainless steel pipe showing stress corrosion

cracking [14]

All alloys are vulnerable to the development of stress corrosion cracking in some

few specific environments, and only pure metals seem to be resistant to it. Table 1.4

shows the typical metal – environment combination where stress corrosion cracking

usually occurs. Although it is found frequently in metals, it can also occur in other type of

solid materials, such as ceramics and polymers. Any surface discontinuity such a

mechanical crack or pit created on the metal surface by crevice corrosion or from

localized attack may act as a stress raiser, and thereby serve as a site for initiation of

stress corrosion cracking [10].

16

Table 1.4: Common metal-environment combination leading to stress corrosion cracking [8]

ALLOYS ENVIRONMENT

Carbon steel, moderate strength Caustic; nitrates; carbonates; bicarbonates;

anhydrous liquid NH3; moist H2S

Carbon steels, high strength

Natural waters; distilled water; aerated

solutions Cl-, NO3-; SO4

2-; PO43-; OH-;

liquid NH3; many organic compounds

Stainless steels Chlorides, caustic; water + Oxygen

Nickel alloys

Hot caustic; molten chlorides; high

temperature water and steam contaminated

with O2, Pb, Cl-, F-, or H2S

Copper alloys Ammonia; fumes from HNO3; SO2 in air +

water vapour; mercury

Aluminum alloys

Aqueous solutions especially with halogen

ions; water; water vapour; N2O4; HNO3;

oils; alcohols; CCl4; mercury

Titanium alloys

Red fuming HNO3; dilute HCl or H2S4;

methanol and ethanol, chlorinated or

bicarbonated hydrocarbons; molten salt;

Cl2; H2; HCl gas

Zirconium alloys

Organic liquids with halides; aqueous

halide solutions; hot and fused salts;

halogen vapors

Magnesium alloys Water + oxygen; very dilute salt solutions

Experience has demonstrated that insulation materials, used in chemical plants

and in offshore facilities containing a few parts per million of chloride, give rise to stress

corrosion cracking, especially on stainless steel alloys, when water penetrates the

17

insulation and leaches out the chlorides [8]. The main factors affecting stress corrosion

cracking are temperature, solution corrosive concentration, stress intensity, metal

composition and structure. The incidence of stress corrosion cracking is greater at higher

temperatures and time to failure is shorter [4]. Stress corrosion cracks appear to be the

result of a brittle mechanical fracture, when in reality they are the consequence of

corrosion processes [6].

1.3.5 Hydrogen Damage

Hydrogen damage refers to mechanical damage of a metal that results from the

simultaneous action of hydrogen and residual or applied tensile stress. Hydrogen damage

appears on specific metals and alloys in different ways such as cracking, blistering and

embrittlement [10]. An example of a failed steel pipe due to hydrogen action is shown in

Figure 1.6.

Figure 1.6: Hydrogen damage on a steel pipe [7]

18

Atomic hydrogen is an element that can diffuse inside metals and initiate the

damage. Therefore, hydrogen damage is caused only by the atomic form of hydrogen.

Usually some of the hydrogen atoms form hydrogen gas and escape as gas bubbles, but at

the same time a fraction of the atoms may penetrate into the metal and once inside, they

can form gaseous molecular hydrogen and cause sudden and unexpected failures. Atomic

hydrogen can be produced by corrosion reactions, by high temperatures moist

atmospheres, by electrolysis process or during pouring of the molten metal [3].

Usually hydrogen embrittlement occurs when there is an applied tensile stress and

hydrogen is dissolved in the metal. Actually this type of corrosion is not well understood

and especially hydrogen embrittlement detection is one of the most difficult features of

the problem [15]. One of the best accepted theories that describes hydrogen

embrittlement is that hydrogen atoms disseminate ahead of a fracture tip and affect the

bonding between metal atoms, causing microcracks ahead of the principal crack, and

thereby the fracture will increase under tensile stress that is below the yield strength. [8].

Not all metals and alloys are affected by hydrogen embrittlement. The most susceptible

metallic materials to this type of corrosion are: medium and high strength steels, titanium

alloys and aluminum alloys [15].

Any macroscopic defect in the steel or even a void offers a region for hydrogen

atoms to combine, produce hydrogen gas, and build enough pressure to cause hydrogen

damage. Usually during the corrosion process there is a period of time when any

evidence of damage is appreciable, followed by abrupt and catastrophic failure [4].

1.3.6 Intergranular Corrosion

The microstructure of metallic materials is formed by grains, divided by grain

boundaries. This type of corrosion refers to the preferential attack at and adjacent to grain

19

boundaries, while the grains remain mostly unaltered [15]. Intergranular corrosion can

occur in the absence of stress. Impurities at the grain boundaries of metals is one of the

factors that can cause this type of corrosion. [6]

This class of localized attack is typically associated with the segregation of

specific components or the development of a compound in the grain boundary.

Intergranular corrosion typically manifests itself along a narrow path beside the grain

boundary. In extreme cases, the complete grains may be removed due to total

deterioration of their boundaries and thereby the mechanical properties of the structure

will be seriously affected [16]. Figure 1.7 shows an example of intergranular corrosion of

a fireplug component.

Figure 1.7: Intergranular corrosion in a fireplug component [16]

20

1.3.7 Galvanic Corrosion

Galvanic corrosion or bimetallic corrosion is the most known of all forms of

electrochemical corrosion. When two different metals are placed in contact in a corrosive

or conductive solution, the less corrosion resistant of the metals becomes anodic and will

corrode while the more corrosion resistant metal becomes cathodic and will remain

almost unaffected. This combination of dissimilar metals is known as a bimetallic couple

or galvanic cell [4]. Figure 1.8 shows an example of galvanic corrosion between a carbon

steel pipe and a brass valve.

Figure 1.8: Galvanic corrosion between a carbon steel pipe and a brass valve [11]

The cathode – anode area ratio is an important factor in determining how fast the

corrosion process will be in a galvanic cell. The severity of damage in a bimetallic couple

21

is proportional to the total cathodic area exposed to the corrosive solution. In more

common terms, the cathode –anode area principle can be described as follows [4]:

• Large cathode and small anode = severe corrosion (5)

• Small cathode and large anode = minor corrosion (6)

Another factor that affects the intensity of galvanic corrosion is the composition and

amount of moisture present in the atmosphere. The corrosion process is more severe in an

offshore atmosphere than in a dry inland atmosphere. Moisture in offshore areas contains

salt and therefore is more corrosive and conductive than moisture in an inland location,

even under the same percentage of humidity and temperature conditions [6].

1.3.8 Selective Leaching

Selective leaching refers to the deterioration of one metal from an alloy by

corrosion processes while the other components remain unaffected [6]. This corrosion

process is a class of galvanic corrosion on a microscopic scale [8]. The most common

example is shown in Figure 1.9 where zinc is leached out of a brass pipe. Usually the

dimensions of the affected area do not change considerably when selective leaching

occurs and corrosion sometimes appears to be superficial [6]

22

Figure 1.9: Removal of zinc from a brass pipe due to selective leaching process [11]

Selective leaching is usually a very slow process that leaves the metal in a

weakened condition where stress corrosion cracking may occur in the presence of tensile

stress [8]. This type of corrosion does not occur with all types of alloys. Selective

leaching represents a very serious problem because of unexpected failures may occur due

to the poor strength of the attacked metal [6].

23

1.4 Scope of the Project

As was mentioned before, corrosion under insulation will continue to persist as world

offshore petroleum activity increases. The offshore exploration and production activities

in the east coast of Canada are not excluded from this fact. This work is focused on the

following objectives:

1- Develop a technical understanding of the problem of corrosion under

insulation on offshore facilities, and recognize the main factors that contribute to the

phenomenon. Additionally this work evaluates whether the natural environment of the

east coast of Canada creates a larger or lesser concern on the occurrence of corrosion

under insulation than that observed in other offshore areas such as the North Sea or the

Gulf of Mexico.

2- Industry practices for the inspection of corrosion under insulation will be reviewed

as well as the evaluation of the integrity of the insulation itself along with the associated

weather barriers such as metal jackets, sealing materials, and coating systems that are

applied to piping and vessels prior to installing insulation. Identification of the inspection

techniques and risk based management approaches that are currently in use, along with a

discussion on their capacity and limitation are also examined.

3- Identify opportunities for new, or for improvements to existing

inspection techniques and risk based management approaches to improve

the detection of corrosion under insulation, to detect deterioration to insulation,

sealing materials, coatings systems applied under insulation, and to appropriately manage

findings such that asset integrity is effectively and efficiently maintained for the planned

life span of the oil and gas offshore structures.

24

2. INSULATION SYSTEMS

The purpose of this chapter is to give a general description of the mechanism of

the insulation systems, the properties of insulation systems, types and forms of insulation

materials and related accessories, design and selection considerations, and failure

mechanisms.

Insulation systems are usually known as materials or combination of materials

that reduce heat transfer from a hot area such as the internal wall of a vessel to a colder

region. The movement of heat can occur in different modes: conduction, radiation,

convection or a combination of these [17]. These heat transfer modes are described in

Section 2.1. The term "thermal insulation" usually applies to insulation systems used on

equipment whose working temperature ranges from -75°C to 815°C. Insulation materials

that are used on equipment working at temperatures below -75°C are termed “cryogenic”

and those above 815°C are termed "refractory" [18].

In the recent years, the insulation industry has developed improved insulation

materials to ensure effective energy conservation. The use of insulation contributes in

reducing the energy requirements of any system. The majority of insulation materials can

reduce at least 90% of the undesired heat transfer as compared to bare surfaces. The

proper selection and the mode of installation of the insulation systems play an important

role in energy management [21].

Based on the purpose for which the insulation materials are used the following

four categories are recognized:

1. Reduction of heat loss: as was mentioned before, the main reason for using insulation

systems is to conserve energy by reducing heat loss or gain of vessels, piping, and

25

equipment. The direct benefit of this reduction is the cost savings in fuel required to meet

the operational or process requirements [20].

The selection of the type of insulation system as well as its optimal thickness for a

specific offshore process or equipment are important factors from the economic stand

point in order to find which will have the best performance in energy conservation over

the planned period of operation of the offshore structure [20].

Usually, for a given set of operating and economic variables there will be just one

insulation system that will cover the desired requirements. One of the main factors that is

considered during the selection of the insulation system for heat loss reduction is the

highest recommended temperature at which the properties of the insulation material will

not be affected. Sealants and caulking systems commonly used to seal gaps that result

from the insulation of irregular sections such as equipment support brackets or to seal end

sections are usually the weakest component in the insulation system [20].

Offshore facilities such as piping and vessels are insulated mostly to conserve

heat. Thermal insulation becomes an important factor for enhancing the product flow

properties, especially in the case of paraffinic crudes or wet gas where the product must

be maintained above the temperature at which paraffin crystals or gas hydrates start to

form and cause difficulties to the product flow [21]. Additional reasons of using

insulation in offshore production platforms are to increase cool –down time of products

after shutting down and also to control the operational parameters of the systems [22].

2. Condensation Prevention: Condensation prevention is the second principal reason of

applying insulation systems on pipes and equipments carrying cold fluids after heat gain

prevention [22]. Since the operating temperature of cold systems can be below the dew

point at which moisture in the offshore atmosphere may condense and form an electrolyte

26

film over the metal surface of pipes and equipment, the use of insulation systems provide

the additional benefit of preventing the initiation of corrosion processes.

3. Personnel Protection: In the case of hot systems where energy conservation is not a

consideration, the control of surface temperature is necessary from the stand point of

personnel safety and comfort. Normally any hot surface such a hot pipe or vessel must be

insulated in order to maintain the surface temperature of the insulation below 48 °C at

which the skin of a person will not burn [20].

4. Noise Reduction: The last consideration for applying insulation materials is noise

attenuation. In some particular cases it is desired to reduce the noise that may be

generated by equipments or piping systems, mainly for comfort reasons.

In addition to the previous four categories, insulation systems could also provide

additional benefits [17]:

• Prevent damage to equipment from exposure to fire or corrosive environments

• Offer additional structural strength

• Reduce water vapor diffusion

• Enhance operating efficiency of heating and cooling systems

2.1 Heat Transfer Properties

Insulation materials are specially designed to reduce the three ways of heat energy

transfer: conduction, convection and radiation. Figure 1.10 shows a schematic

representation of the heat transfer modes. Contrary to what one may think, conduction is

not the only manner of heat propagation that takes place within insulation systems. Most

of insulation materials are porous and hold small pockets of air. Additionally, a thin film

27

of liquid or air may be present between the insulation material and the equipment on

which it is installed. Therefore conduction in not the only way of heat transfer [20].

Figure 2.1: Heat transfer modes [23]

Heat will continue to flow as long as a temperature difference exists between the

equipment to be insulated and the surrounding atmosphere [19]. In this section a brief

description of the various modes by which heat can flow is presented in order to have a

better understanding of the basic principles of heat flow on which insulation systems are

based.

2.1.1 Conduction

Conduction is defined as: “the process by which heat flows from a region of

higher temperature to a region of lower temperature within a medium (solid, liquid or

28

gaseous), or between different media in direct physical contact” [23]. The principal

process by which heat flows through insulation materials is conduction [20]. The heat is

transferred by molecular contact, where heated molecules vibrate and transmit the energy

to cooler molecules. Gas and solid conduction are the principal factors in insulation

technology [21].

2.1.2 Convection

Convection is the process by which heat flows through liquids or gases. It does

not occur in solids. The heated fluid becomes less dense and therefore will rise and take

the heat energy with it. Colder and heavier fluid will replace the empty space left by the

hot fluid [20]. Convection process is virtually eliminated within porous insulation

materials. The temperature difference within the cells is so small that the convection

process will not occur [19].

2.1.3 Radiation

Radiation is “a process by which heat flows from a higher temperature body to a

lower temperature body when the two bodies are not in contact” [23]. The heat is

transported by waves similar to radio waves emitted by the hot substance. The energy

transmitted in this way is called radiant heat. Any fluid or solid is able to radiate heat. As

the temperature of the radiating substance increases, the intensity of the emission will

also increase [20].

When radiation waves reach another body, the heat is either absorbed by its cold

surface, is transmitted through or absorbed. One of the methods to control the radiation

process is by inserting absorbers or reflectors within insulation materials. Another factor

that affects radiation is the density of the material. At higher density values the radiation

process is reduced but convection and material costs increase. Therefore it is very

important to understand the different modes of heat transfer during insulation design [19].

29

2.2 Thermal Properties

During the process of design and selection of particular insulating materials there

are four principal thermal properties that have to be taken in consideration in order to

cover the operational and safety requirements of any offshore and onshore processing

system.

In this section, a general description of the four main properties that must be

considered in the selection of an insulating material is presented.

2.2.1 Thermal Conductivity

The efficiency of insulation materials is measured by a property called thermal

conductivity which refers to the ability of a material to conduct heat [19]. It is denoted

with the letter “k” and is expressed in Watts per metre per degree Celsius (W / m x °C).

This property measures the amount of heat that is transmitted in one hour through a

homogeneous material per unit thickness in a direction perpendicular to a surface [20].

The driving force for the flow of heat is the temperature difference between opposite

sides of the insulation material [21]. As the thermal conductivity increases, the heat flow

increases. Therefore this property is very important in selecting insulation systems.

One of the features related to the thermal conductivity is that it changes with

temperature and it is usually published on tables per mean temperature and not related to

operating temperature. The mean temperature is the average temperature of the insulation

and is calculated with the sum of the hot and cold surface temperatures and dividing the

value by two. Another factor that is important to know is that it also changes with time.

Some insulation materials have their cells filled with a special gas that decreases the

thermal conductivity, but usually after manufacture, some percentage of this gas diffuses

out of the insulation and thereby the thermal conductivity increases [19]. In the

30

appendices section there are several tables available of various types of insulation

materials with their thermal conductivity properties as a reference.

2.2.2 Thermal Conductance

Thermal conductance refers to the quantity of heat that is transmitted through a

homogeneous material of an arbitrary thickness [20]. It is denoted by the letter ‘C’ and

expressed in Watts per metre square per degree Celsius (W / m2 x °C). The following

formula is usually used to calculate the conductance of different materials:

C = k (7) t Where:

k = thermal conductivity (W / m x °C)

t = Insulation thickness (metre)

2.2.3 Thermal Transmittance

Thermal transmittance is defined as “the measure of heat energy transmitted by a

material or assembly including the boundary air films” [23]. It refers to the amount of

heat that is transmitted through one square metre of a material. It is denoted with the

letter “U” and expressed in Watts per metre square per Celsius (W / m2 x °C).

2.2.4 Thermal Resistance

Thermal resistance as the name indicates is the resistance of solid materials to the

heat flow. It is denoted with the letter “R” and expressed in metre degree Celsius per

Watts (m x °C / W). The following formula can be used to calculate the thermal

resistance of materials [23]:

31

R = t/ k = 1/C = 1/U (8)

Where:

t = Insulation thickness

k = Thermal conductivity

C = Thermal conductance

U = Thermal transmittance

Heat flow can be reduced by increasing the thermal resistance of the insulation

system. In the case of various materials assembled together in series, the total thermal

resistance of the insulation system will be the sum of all the individual resistances of each

material [19].

2.3 Mechanical and Chemical Properties

In some specific applications, for example, offshore facilities, other properties

beside thermal properties are considered in the selection of an insulation material.

Depending on the characteristics of the geometry of the equipment to be insulated and

also additional factors such as: characteristics of the surrounding environment,

combustibility of the material, compressive strength and chemical composition of the

insulation, the type of insulation system will vary from one particular application to

another.

In this section some of these additional properties and factors are described in

order to explain the complexity in the selection of an insulation system that could cover

all the requirements of a specific system other than energy conservation.

32

2.3.1 Density

Density of the insulation material is an important property for calculating the

loads on the support structures. It also affects other properties such as compressive

strength and thermal conductivity. Sometimes the density of the insulation material will

be related to the ease of installation of the product; therefore for applications where there

is not too much space available to install the insulation system, a flexible and less dense

material may be considered [19].

2.3.2 Moisture Resistance

Insulation systems are most effective when they are dry. In the case of offshore

applications, the moisture resistance or the ability of the insulation material to resist

vapor moisture intrusion is very important in order to achieve the effectiveness of the

insulation and prevent further corrosion problems.

The moisture resistance capacity will vary depending on the type of material and

its cell structure. The quantity of moisture that can be absorbed by an insulation material

will be determined by the internal cell structure of the product. Closed cell insulations,

like cellular glass type, have the capacity to prevent the diffusion of water vapor into the

insulation [19]. However, most of the insulation systems are able to absorb, accumulate

and transmit water or water vapor throughout the insulation. It is common to combine

weather or vapor barriers such as metal jackets or mastics with the insulation material in

order to prevent the ingress of water into the insulation [17].

The moisture resistance effectiveness of insulation materials can be calculated by

measuring the flow of water vapor, also called permeance through the insulation material.

It is measured in perm-inch that refers to “the weight of water, in grains, that is

transmitted through a 25 millimetre thickness or one inch of the material in question in

33

one hour and one foot square, having a pressure difference between faces of one inch of

mercury. The higher the value of permeance the higher amount of water vapor that is able

to diffuse into the insulation material [20]. Table 2.1 shows a list of different insulation

materials and their general moisture resistance.

Table 2.1: Moisture resistance property of various insulation materials [24]

Insulation material Permeance (perm-inch)

Cellular glass 0.00

Flexible elastomeric 0.09

Cellular polystyrene 1 to 3

Phenolic 1 to 3 Polyisocyanurate 1 to 3

Polyurethane 1 to 3 Fibrous glass 40 to 110

2.3.3 Compressive Strength

Compressive strength is an important property to be considered in the selection of

an insulating material if the insulation must support a load or will be subjected to

mechanical abuse such as climbing over and foot traffic [18]. Usually this property gives

an idea of how much deformation could occur under specific loads. A common reference

value at which compressive strength is reported and compared is five and ten percent of

deformation [19]. Table 2.2 shows a list of insulation materials and their compressive

strength value at five and 10 percent of deformation.

34

Table 2.2: Compressive strength of different insulation materials [22]

1. CCPUF = Closed cell polyurethane foam 2. OCPUF = Open cell polyurethane foam 3. PIF = Poly-isocyanurate foam 4. VIP = Vacuum Insulation Panels 5. PU = Polyurethane 6 PP = Polypropylene

2.3.4 Temperature Use Range

The expected operating temperature range of a pipe, vessel or any uninsulated

equipment is a very important factor in the selection of an insulating material. For a hot

35

or cold system, the maximum expected temperature will dictate the selection of the

product and the adhesive used to bond the insulation to the equipment and itself [20].

All insulation systems have a recommended temperature range at which the

system is designed to maintain its integrity and capability to perform its function. Usually

the insulation systems experience a physical change when the recommended service

temperature is exceeded. There are industry standards where the temperature range is

specified for every type of insulation material, but frequently the manufacturers provide

their own acceptance service temperature [19]. Table 2.3 shows a comparative list of

generic insulation materials with their recommended service temperature.

Table: 2.3: Recommended thermal temperatures by Du Pont Company [25] Generic Insulation Materials Recommended Service Temperature ◦ C

Polystyrene foam -73 to 60

Polyurethane foam –rigid -73 to 82

Polyisocyanurate – rigid -73 to 149

Flexible foamed elastomer 2 to 82

Cellular glass -129 to 149

Glass fiber 4 to 190 or 454 (depending on type)

Mineral wool 60 to 649 or 982 (depending on type)

Calcium silicate 60 to 649

Perlite silicate 60 to 593

2.3.5 Fireproofing

The contribution of insulation systems used on offshore facilities or other types of

applications to a fire hazard is a very important property to be considered especially

36

where fuels, liquids or other flammable materials are involved in the operational

activities. Offshore facilities are a good example of this case and are always exposed to a

potential fire. Exploration and production activities involve the use, handling and

processing of flammable products such as diesel, condensates or natural gas for power

generation, or oil and gas that is produced from the offshore reservoirs.

Any part of the offshore structure and equipment including their contents may

contribute to fire hazard by sustaining combustion or producing smoke [20]. Usually

insulation systems can be divided into two groups, those that have the ability to withstand

fire exposure or those that have the ability to develop smoke or spread flame [19].

Generally, insulation materials are tested for smoke developed, flame spread, and

fuel contributed. The materials are compared to red oak flooring rated at hundred and

asbestos –cement board rated at zero. The accepted value for flame spread is 25 and 50

for smoke developed and fuel contributed. However these values may vary from one

application to another [20].

2.3.6 Sound Attenuation

This property is considered in some applications where sound transmission may

be a problem. Usually in this case, an extra thickness of insulation or special jackets is

used to reduce the sound to an acceptable level [20].

2.3.7 Chemical Neutrality

Insulation materials should not contribute to the deterioration of metal, mainly if

water and moisture diffuse into the insulation. The material should be chemically neutral

or alkaline to prevent corrosion. Figure 2.2 shows the corrosion rate of iron versus pH

levels of aerated water. The red line represents the rates of corrosion under insulation

37

systems. Some insulation materials contain substances that are leached out when they are

wet that may decrease the pH of water and create a very corrosive medium for the

insulated pipe or equipment. Therefore this characteristic should be considered

principally for offshore application where a risk of water intrusion is present.

Figure 2.2: Effect of pH on corrosion rate of iron in aerated water [26]

2.3.8 Other Properties

Additional properties and factors may be considered in the selection of the proper

insulation system. The available form of the insulation material is one of them. Some

insulation materials can fulfill the thermal and other requirements for a particular

application, but they may not be available in a compatible form. The most common

forms of insulation materials are: rigid boards and blocks, flexible sheets and blankets,

pre-formed shapes such as curved segments and halve pipes [19]. Figure 2.3 and 2.4

38

show an example of a typical rigid block insulation used on vessels and a pre-formed

pipe insulation system.

Figure 2.3: Typical vessel insulation using rigid blocks [27]

39

Figure 2.4: Typical pre-formed pipe insulation multilayer construction [27]

Another factor that may dictate the selection of the insulation system is the

capacity of the insulation to be removable and reusable. Some equipment such as valves

and flanges require frequent maintenance and if they are insulated, the insulation material

could lose its insulation capacity if the product is not capable of withstanding the removal

and reinstallation action on a regular basis [21]. Figure 2.5 shows an example of a

removable and reusable insulation system on a valve.

40

Figure 2.5: Removable and reusable insulation system [28]

2.4 Insulation Materials

Nowadays there are a variety of insulation materials available for any type of

application. Some products have been in the market for a long period of time, while

others such as the new type of areogels are relatively new. In the following section, a

general description of the primary insulation materials is presented. In the Appendices

section there are tables available that provide a list of the most common insulation

materials and their properties.

2.4.1 Calcium Silicate

Calcium silicate is a rigid insulation produced from silica and lime and reinforced

with organic and inorganic fibers. This insulation product is known for its excellent

compressive strength property and durability. The recommended service temperature

41

varies from 35°C to 815°C depending on the manufacturer [18]. However, because it can

absorb nearly 400 % of its weight when immersed in water and in humid conditions 20 to

25% by weight water; most manufacturers recommend a lower temperature limit of about

150°C for outdoor applications [27].

This type of material when wetted has a pH between 9 and 10. Some coatings that

are applied on the surface of metals before the insulation such as inorganic zinc may be

affected with high pH solutions [27].

2.4.2 Expanded Perlite

This product is made from perlite mineral that during its manufacturing process is

expanded and combined with sodium silicates as binders. It has a maximum

recommended service temperature of 593 °C. At higher temperature values, it starts to

shrink very fast [25]. Its physical structure is based on small air cells surrounded by

vitrified product. This insulation material resists moisture penetration due to the addition

of water resistance additives, is non-combustible, and comes in sheets and rigid pre -

formed shapes [18].

Expanded perlite starts losing its water resistance property at temperatures around

315°C, because some additives burn out and water absorption increases [27].

2.4.3 Glass and Mineral Fibers

Fibrous mineral and glass products are available in a variety of forms such as

rigid and semi-rigid boards, flexible blankets or semicircular sections for pipe insulation.

They are produced from the molten state of rocks, slag or glass that is converted into a

fibrous form with the combination of organic heat resistant binders [27].

42

Fiberglass is the most popular insulation material, having a bulk density that

ranges from 24 to 96 kg/m3 depending upon the manufacturer, has a poor compressive

strength property, a thermal conduction (k) value between 0.22 to 0.26 W / m x °C and

a thermal resistance (R) value between 3.8 to 4.5 m x °C / W . Service temperatures

range from 1.5°C to 422°C. The binder systems employed during the manufacturing

process are the important factor that dictates the highest temperature at which it can be

used [20]. Some binders get damaged in the presence of water combined with high

temperatures where the resulting solution could act as a triggering factor for a corrosion

process [27].

Fibrous insulations have the capacity to absorb water and moisture due to their

porous structure. Therefore, weather barriers such as metal jackets are used to prevent the

ingress of water and moisture into the insulation.

2.4.4 Cellular Glass

Cellular glass insulation is composed of pure sealed glass cells. This product

comes in rigid forms such as boards and pre-formed pipe coverings. It is completely

inorganic and has an average compressive resistance value of 690 kPa [19].

This product does not absorb any quantity of moisture or water; has good structural

strength, but is brittle to some extent. It is also resistant to common acids and corrosive

environments and has excellent fire resistant properties [18]. However the thermal

conductivity value is higher compared to other insulation materials, but because of its

special features, this type of insulation material is highly recommended for offshore

applications [19].

43

2.4.5 Polyurethane and Polyisocyanurate Foams

These two types of insulation materials are available in rigid forms and are

commonly used in industrial applications. They have an excellent value of thermal

conductivity that ranges from 0.020 W / m x °C to 0.042 W / m x °C, but they have poor

fire resistance characteristics, especially the polyurethane foams. Polyisocyanurate

insulations were created to improve the fire resistant properties but they still have not

reached the 25/50 fire hazard classification (25/50 FHC) [19].

Polyurethane and Polyisocyanurate foams do not absorb water as long as their cell

structure is not affected. The recommended service temperatures range from -73°C to

149°C for Polyisocyanurate foams and from -73°C to 82°C for polyurethane foams with a

compressive resistance value of 17 kPa at 5 % of deformation [25].

These materials, as well as other insulations contain substances such as chlorides,

fluorides, silicates and sodium ions that when wet, leach out of the insulation and may

produce a low pH solution that accelerates the corrosion process of any insulated metallic

equipment. The pH value could range from 1.7 to 10, but when the value is below 6.0, the

corrosion rate of metals usually increases and special concerns should be given [27].

2.4.6 Elastomeric Foams

Elastomeric foam insulations are a mixture of foamed resins and elastomers that

produce a flexible closed cell material. They are manufactured in a variety of forms

including pre-formed shapes and sheets. The maximum recommended temperature is

around 105°C depending upon the manufacturer. This product is commonly used for cold

service systems and does not require vapor barrier protection. The principal disadvantage

of this type of insulation is its smoke generation capacity. [18].

44

2.4.7Aerogels

Aerogel insulations were first manufactured in the year 1931, but due to the

complicated manufacturing process, their large scale commercial application was not

possible. They are produced from a polymerization reaction where polysilicic acid creates

a firm structure that during the drying process, the processing water is removed and

replaced with air that is hold in its structural matrix [21].

During the last few years, new technologies have made possible the improvement

of the production process by reducing the drying time and the manufacture of flexible and

thin blankets. The new aerogel product has smaller pores in its structure that reduce the

free diffusion of gas molecules through the insulation and thereby improves its thermal

performance. The product offers the lowest thermal conductivity and does not absorb

moisture due to its hydrophobic property [21].

2.5 Protective Coverings and Finishes

The proper performance of insulation materials depends upon their protection

from mechanical and chemical damage and also from water and moisture ingress. A

variety of jacketing systems and finish materials are produced and applied in conjunction

with insulation materials to ensure the long term performance of the whole insulation

system [18]. In the appendix section, detailed tables are presented with more

characteristics of protective material and accessories.

The following section presents a general description of the additional accessory

materials that are used with the insulation systems.

45

2.5.1 Adhesives

For some applications, adhesives materials such as adhesive tapes are used to

secure insulation materials to equipment surfaces. The principal problem that has been

experienced with the use of some adhesives on austenitic stainless steel is that they have

caused stress corrosion cracking. The main reason is that some adhesives are

manufactured with chlorides and other components that when wet are leached out and

produce corrosive solutions that attack the metal surface [27].

2.5.2 Cements

Cements are used to bond insulation materials into the desired shape. Asphaltic

based cements are used for cold systems. Special concern must be given to some cement

materials which contain chlorinated polymers that are intended to be used for insulating

austenitic stainless steels, because they may promote the initiation of corrosion processes

if those polymers are leached out when water ingress into the insulation [27].

2.5.3 Coatings and Mastics

Coatings and mastics are applied over insulation materials to retard the diffusion

of water vapor into the insulation. If they are used without jacketing systems in outdoor

applications, they must be capable of resisting ultraviolet radiation and fire exposure.

Therefore frequent inspection is necessary to maintain the integrity of the insulation

system [18].

46

2.5.4 Sealants and Caulks

Sealants and caulks are designed to seal jacket systems, joints and protrusions. A

common cause of water ingress into the insulation is the failure of sealant and caulking

systems [26]. Figure 2.6 shows an example of a typical insulation system with caulking

compound near a pressure gauge attached to the pipe.

Figure 2.6: Typical insulation system where caulking compounds are used [27]

Because caulking and sealant systems are very susceptible to fail due to

mechanical abuse and other factors, frequent monitoring programs are necessary to keep

insulation systems in good condition and prevent the ease of water intrusion [27].

47

2.5.5 Jacketing Systems

Jacketing systems, also known as weather or vapor barriers, represent the first line

of defense and protection of insulation systems against mechanical abuse, corrosive

atmospheres, water intrusion and fire exposure. Special consideration should be given to

jacketing materials that are used for mechanical protection of insulation materials with

low compressive strength, because they are very susceptible to physical damage,

allowing water ingress [18].

Jacketing materials that are frequently used include fiberglass reinforced plastic,

stainless steel, aluminum, galvanized steel, tape systems and reinforced fabrics [27]. The

condition of the insulated equipment and the insulation material itself will depend upon

the capacity of jacketing systems to maintain their technical integrity over the planned

lifecycle of the equipment [20]. Figure 2.7 shows an example of a vapor barrier applied

over an insulation material

Figure 2.7: Rubberized asphalt vapor barrier membrane on an ammonia system [24]

48

2.5.5.1 Aluminum Jackets

Aluminum jackets come in different thicknesses and in corrugated or smooth

shapes. Because they are less costly than stainless steel jacketing, their use is more

common. Aluminum jackets are usually secured with screws, straps or with a patented

seam in a Z or S pattern. Figure 2.8 shows an insulated pipe with aluminum jacket

secured with screws [20]

Figure 2.8: Aluminum jackets secured with screws [29]

Usually a variety of coatings and vapor barriers are applied to aluminum jackets,

especially if the insulation may have some substance that can cause corrosive attack on

the aluminum. For application where the insulated equipment suffers frequent expansions

and contractions, corrugated aluminum jackets are used in order to absorb the physical

changes of the equipment [20].

49

2.5.5.2 Stainless Steel Jackets

Stainless steel jackets come in corrugated or flat shapes. The most frequently

available alloys are types 302, 304 and 316. They are available in a variety of thicknesses

and are secured in the same way as aluminum jackets. Since they are more expensive

than aluminum jackets, their use is restricted to special applications such as insulation

systems that are required to be fire resistant [27].

This type of material is susceptible to stress corrosion cracking in contact with

leachable chloride ions presented in insulation materials. Therefore stainless steel

jacketing is usually supplied with a inner coating film to prevent the rapid deterioration of

the metal. In order to prevent the occurrence of galvanic corrosion, stainless steel bands

are used to secure this type of jacket [27].

2.5.5.3 Plastic Jackets

Plastic jackets are available in a variety of materials, such as polyvinyl chlorides

(PVC) and polyvinyl fluorides (PVF). These thermoplastic materials are not often used

for outdoor applications because of their poor resistance to mechanical abuse and

ultraviolet radiation, low melting point and corrosion by different chemicals. These

materials are commonly used for indoor applications [27].

2.5.5.4 All Service Jackets

The all service jacket (ASJ) or all purpose jacket consist of three layers of

different materials that form the complete jacket system. The most common material that

serves as the base of the system is kraft paper that has been coated. A fiberglass cloth is

placed over the kraft paper in order to provide strength to the system. Finally a layer of

50

aluminum foil or metalized film is added over the fiberglass cloth. A special adhesive is

used to bond permanently the three materials and provide the desired strength and water

vapor resistant properties [20].

2.6 Insulation Failure Mechanism

The most common failure mechanism of all insulation systems is the one related

to water ingress into insulations. If water in the liquid, solid or vapor state is present in

the insulation, it will cause serious effects on the thermal properties of the insulation

system; it may affect the physical structure of the insulation material and also it may

cause deterioration of the insulated equipment due to corrosion [17].

The hydroscopic properties of insulation materials are very important in the

prevention of water diffusion into the insulation, but in reality there is no ideal insulation

system currently available that will protect against water ingress during its designed

operating life.

Mechanical abuse such as personnel walking on insulated equipment can be

considered as the primary cause of water ingress into insulation systems. Mastics,

sealants, weather and vapor barriers are the critical components of insulation systems that

are more vulnerable to mechanical abuse since they are used and designed to protect and

seal the insulation. As the time passes, ultraviolet radiations, water and chemicals used

for cleaning purposes may also promote the damage and failure of vapor and weather

barriers. Therefore periodic inspections must be performed in order to maintain insulation

systems in a good and dry condition [27].

Sometimes jacketing systems are not properly installed and finished, leaving a

gap between joints and allowing water to bypass the insulation. Figure 2.9 shows a

typical example of a jacket material installed without proper finish [2].

51

Figure 2.9: Improper finishing of jacketing system [2]

Unsealed insulation end sections are another example of improper installation of

insulation systems where weather barriers may be installed without the combination of

sealing materials and end caps. Figure 2.10 is a typical case of an unsealed insulation end

section where water can easily penetrate the insulation and cause corrosion problems [2].

52

Figure 2.10: Improper sealing of an insulation end section [2]

A common inefficient installation scenario that allows water into the insulated

equipment is on vertical sections where lower sections of weather barriers are installed

over the top of upper sections. Figure 2.11 shows an example of this particular case. On

horizontal sections the typical installation error is when jacket laps are installed at the

bottom or top of piping instead of near the sides. Figure 2.12 shows an insulated pipe

with jacket laps installed close to the top section [2].

53

Figure 2.11: Lower section of an aluminum jacketing system installed over the upper section [2]

Figure 2.12: Aluminum jacket laps installed near the top section of piping [2]

54

The configuration of piping and equipments that need to be insulated and also the

shape and orientation of the attachments are important factors of insulation system

design. Usually piping and vessel attachments and equipment supports are difficult areas

to insulate and seal due to their geometry and thereby represent vulnerable places where

water may bypass insulation and cause deterioration of the underlying metal surface.

Figure 2.13 is an example of typical vessel attachments where water can penetrate

insulation systems [27].

Figure 2.13: Typical vessel attachments where water may bypass insulation [27]

55

3. OIL AND GAS OFFSHORE STRUCTURES

Oil and gas offshore activities began in the year 1896 when initial drilling efforts

where made off of the coast of California using fixed platforms. It was not until 1946

when offshore exploration and production activities started to increase when nine wells

were drilled from rigid structures off of the coast of Louisiana in the Gulf of Mexico. The

following year a mobile platform was used to drill an offshore well located 12 miles from

the Louisiana shore [30]. Since then, the oil and gas industry has developed a variety of

offshore structures that allow the exploration and exploitation of deeper oil and gas

targets around the world. This chapter describes the different platforms currently being

used in the east coast of Canada and the common types of offshore production facilities

and their related insulated equipment.

In general, offshore drilling and production platforms can be divided into two

different structures: the platform and the topside facilities. The platform is made of steel

or reinforced concrete and supports the topside facilities. It may float or rest on the

seabed. Some platforms may contain silos or tanks to store the oil that is produced. The

upper section or topside facilities is where production activities are carried out [31]. A

typical topside facility on a production platform would include drilling facilities, process

facilities, living quarters, instrumentation systems, electrical systems, storage facilities

and safety systems [32].

Depending on the type of hydrocarbon that is being produced from offshore

fields, topside facilities may vary in size and appearance, particularly the process and

production systems. Another factor that will determine the type of offshore structure to be

used is the water depth where the reservoir is located. Every class of offshore structure

has a maximum water depth capability that limits its use [33]

56

The offshore environment is considered by many as the most severe of the

operating environments. Corrosion problems on offshore insulated facilities are one of

the important challenges that the oil and gas industry has been facing for a long period of

time, principally after the oil crisis in the decade of 1970 that caused the cost of energy to

rise and led to increased use of insulation systems for piping and equipment operating at

lower temperatures [34].

Offshore production facilities in Atlantic Canada are built to withstand the

extreme weather conditions such as winds gusting to 170 kilometers an hour and waves

more than 30 metres high. The additional weight to offshore structures that may result

from freezing spray during the winter season is another factor that is considered in their

design phase. Production platforms are designed for a life cycle of about 25 years with a

potential extension. Depending on their size, offshore facilities may accommodate from

25 to 185 people and normally the employees work up to 21 days in a row [31].

From the corrosion point of view, offshore structures can be divided into three

zones. Figure 3.1 shows the three corrosion areas in an offshore structure and the

standard corrosion control methods for each area [35].

57

Figure 3.1: Areas of corrosion and types of corrosion control for offshore structures [35]

The three zones are defined as:

• The immersed zone: This is known as the area that is below the splash zone and

covers all the submerged sections of the offshore structure including the area

below the mud line. In this zone corrosion rate tends to be uniform [4]

• The splash zone: The splash zone also known as tidal zone is located above the

submerged zone and consists of the section of the structure that is alternately in

and out of the water due to waves, tides and winds. This region is the most

corrosive area due to washing action of the aerated sea water [4].

58

• The atmospheric zone: is the section of the offshore structure that is above the

splash zone and exposed to the air, sun, wind, spray and rain. Unprotected low

alloy steels in the atmospheric zone have shown a mean corrosion rate of about

0.1 millimetres per year, whereas in the splash region corrosion rates have been

measured as high as 0.6 millimetres per year. Depending on the characteristics of

the surrounding environment, the salinity of the sea water and related

contaminants, and other additional external and internal factors, corrosion rates

will be different from one location to another [1]. This project focuses on the

atmospheric region where the topside insulated facilities are located and are

affected by the corrosive marine environment.

Nowadays, there are three different classes of offshore structures that are used for oil

and gas production in the east coast region of Canada. These are:

1. Concrete gravity base structure (GBS): This offshore platform was built of

reinforced concrete for the Hibernia oil field located on the Grand Banks off the

East Coast of Newfoundland and Labrador. The Hibernia gravity base structure

was towed to the oil field and then filled with ballast in order to anchor it to the

seafloor. In the base of the structure there are tanks that are used to store the

produced oil before it is shipped to shore. This offshore development has been

producing oil since November 1997 [31]. Figure 3.2 shows the Hibernia platform.

59

Figure 3.2: Hibernia gravity base structure [31]

2. Fixed steel structure: This type of structure, also known as jacket platform,

represents the backbone of the offshore industry. There are more than 7000 of this

class of offshore installations operating around the world. Figure 3.3 shows one of

the five fixed steel structures currently in use at the Sable Offshore Energy

project, located about nine kilometers off Sable Island, Nova Scotia. The five

offshore platforms were built to produce natural gas from the Thebaud, North

Triumph, Venture, South Venture and Alma fields [31].

60

Figure 3.3: The Thebaud facility [31]

The fixed steel structures consist of tubular steelwork that supports the topside

facilities. Normally the steel legs are transported by barge to the desired place and then

lowered in an upright position to the seabed. The legs are anchored to the seafloor with

steel piles [31]. The accommodation and helideck facilities are always located as far

possible from the processing area for safety reasons [33].

3. Floating production system: The Terra Nova and White Rose oil fields located

on the Grand Banks off Newfoundland and Labrador have been developed with a

Floating Production Storage and Offloading system (FPSO). This type of

structure contains all the equipment related to a fixed installation and is used in

combination with subsea wellheads. The processed oil is stored on board the

vessel and then is discharged into shuttle tankers that transport the product to a

refinery. In case of iceberg hazards, the FPSO can be disconnected from the wells

and can be moved to a safe area. Figure 3.4 shows the SeaRose Floating

Production Storage and Offloading vessel that is currently in use for the White

Rose project [31].

61

Figure 3.4: Floating Production, Storage and Offloading vessel [31]

3.1Topside Facilities

The upper part of offshore facilities accommodates all the equipment also known

as topside facilities, that are necessary to extract, process, store and ship the produced

hydrocarbons to refineries or gas processing plants. Many of the processing and

production systems are insulated in order to control the operating temperatures and also

to protect personnel from a hot surface that may represent a potential risk to the daily

activities. As was mentioned before, topside facilities may vary in size and appearance

from one offshore platform to another, but in general all of them perform the basic

production functions.

The majority of oil and gas offshore structures and processing equipment are

constructed of steel. The steel types commonly used for an offshore installation are

carbon steels and austenitic stainless steel alloys [4]. Carbon steels consist basically of an

62

alloy of carbon and iron containing as much as 1.65% manganese and up to 2% carbon

and some small concentrations of other elements. They are easily fabricated and in

general are the least expensive alloys frequently used. The austenitic stainless steels

represent the “300” series and are extensively used due to their corrosion resistant

properties. The most commonly used are the types 304 and type 316 that contain high

proportions of chromium and nickel [4].

No attempt is made in this chapter to describe every type of topside equipment

that is usually insulated. There are three categories according to its principal function that

topside production facilities can be subdivided into. These are: processing systems,

storage systems and piping systems. The following section gives a general description of

these three types of topside facilities that are frequently insulated and affected by the

corrosive offshore environment.

3.1.1 Processing Systems

The function of the processing facilities on an offshore platform is to remove the

associated water and impurities that may be produced together with hydrocarbon

products and also to separate the crude oil and gas into individual product streams prior

to their transportation to onshore processing facilities. Usually during the exploitation of

an oil reservoir, water and natural gas could be present in the same field. The gas is

usually the component that provides the driving force to bring the crude oil to the topside

processing facilities. Therefore an offshore oil platform may include a gas processing and

injection plant in addition to the oil processing systems [33].

Equipment used to remove water from the crude oil such as free water knockouts

and heater treaters require high temperatures to break the emulsion in the incoming

hydrocarbons. These vessels are normally insulated to reduce the heat transfer to the

atmosphere. The elevated operating temperatures in combination with water ingress into

63

the insulation system create the perfect conditions to promote corrosion problems on the

metal surface of the fluid separators [4].

There are also a number of production separators located downstream of the

production header that is basically a manifold that receives the crude oil from the wells

and distributes it to the different processing systems. The operation of the production

separators rely on the fluid dynamic principles where oil, associated water and gas are

separated. As the produced oil enters the separator the decrease in pressure makes

possible the separation of dissolved gases which are removed from the top part of the

vessel. The oil and water are separated due to variation of the specific gravities of the two

fluids. In the appendices section there is a typical flow diagram showing an oil and

associated gas processing installation [33].

In the case of the process equipment on a gas producing offshore facility, the

produced gas normally enters to a slug catcher where the first fluid separation takes

place. Large volumes of water and sand are removed prior to the gas flowing to the

production header where it is distributed to the processing facilities. Production

separators are also installed downstream in order to separate the remaining fluids and

impurities that may be present in the produced gas [33].

The absorption tower is another equipment that is also found on offshore

processing facilities. It consists of a vertical vessel that uses triethylene glycol (TEG) to

absorb the residual moisture in the gas prior to its transportation to the offshore reception

facilities [33].

Heat exchangers form part of the processing systems. They assist in the separation

of oil from water and also in the regeneration of glycol used in gas dehydration systems.

For further details, in the appendices section there is a flow diagram of a typical gas

processing system including a glycol contactor or absorption tower with the associated

64

glycol regeneration system. Depending on the geometry and configuration of the

processing equipment, the installation of insulation systems may represent a challenge,

especially if the equipment has a variety of attachments and supports that may be difficult

to weatherproof properly, thereby moisture could easily ingress and diffuse through the

insulation material and reach the metal surface creating an ideal condition to start

corrosion processes [27].

3.1.2 Storage Systems

Storage systems as the name implies, consist normally of atmospheric pressure

vessels that are installed on offshore platforms to provide temporary storage for the

produced oil, condensates and water before proceeding to successive processing systems.

The fluid level in storage tanks is maintained between pre established limits by level

sensing devices and pumping systems. The crude oil and related produced fluids may be

also stored in silos within production platforms. Frequently these storage systems contain

hot hydrocarbon products and require the application of insulation systems for personnel

protection and heat conservation [33]. Rigid insulations are typically used to insulate

storage tanks and require good cements and adhesive systems to join insulation materials

to vessel surfaces. Figure 3.5 shows an installation of rigid cellular glass blocks on a

storage tank using urethane adhesive [37]. Incorrect securement of the insulation may

cause premature and unexpected failures of storage tanks due to water and moisture

accumulation at the bottom part and near the insulation support rigs. Figure 3.6 shows a

corroded vertical vessel where water entered into the insulation and accumulated near the

insulation support ring [38].

65

Figure 3.5: Application of rigid cellular glass blocks on a storage tank [37]

Figure 3.6: Corrosion above an insulation support ring [38]

66

3.1.3 Piping Systems

Piping systems are the most common component on an offshore facility where

insulation systems are installed. They represent the link between the christmas tree and

the flow lines used to transport the hydrocarbon products to onshore reception facilities

or to load shuttle tankers. The christmas tree is where the crude oil or gas at full reservoir

pressure and at elevated temperature is admitted to the topside production facilities. It

consists of an assembly of valves which control the flow of hydrocarbons and allows

isolation of the reservoir products from the processing systems [33]. Figure 3.7 shows a

schematic of a christmas tree system. Piping systems connect all the required production

equipment to process the hydrocarbon products that are produced from the reservoir prior

to transportation to onshore refineries.

67

Figure 3.7: Schematic representation of a typical christmas tree system [33]

The design of piping supports and attachments is an important factor of insulation

systems and piping integrity. Sealants and caulking compounds are the only components

of insulation systems that are used to seal the protrusion created at jacketing penetrations

such as rod hangers, monitoring devices, or clamps supporting piping. Unexpected piping

vibration, weather action and chemicals may produce cracks and the rapid deterioration

of these compounds allowing moisture penetration. Figure 3.8 shows an example of

protrusions through jacketing where water may enter into insulation on piping systems

and corrode the metal surface [27].

68

Figure 3.8: Potential places where water may bypass insulation on piping [27]

Proper installation of jacketing systems is also a vital part of insulation and piping

integrity. Insufficient clearance for insulation between piping systems and adjacent

structures is a common problem on offshore facilities due to the confined space that

characterize the offshore structures. Normally insulation jackets must be cut around the

adjacent structure causing discontinuity of the weather barrier and allowing water

intrusion. Figure 3.9 shows an example of jacketing open at a vertical beam where

corrosion under insulation was found [39].

69

Figure 3.9: Insulation jacket open at a vertical beam [39]

3.2 Industry Trend

The oil and gas industry, in the search of new and better corrosion resistant

materials for offshore applications, has replaced the used of austenitic stainless steels

with a new class of alloy known as “duplex stainless steels”. Duplex steels contain

higher levels of chromium that range from 19% to 28%, up to 5% of molybdenum and

lower nickel contents than austenitic stainless steels. These alloys have improved

strength properties over other corrosion resistant alloys [40]. The yield strength can vary

70

from 760 to 860 x 106 Pascal (760 to 860 MPa). Duplex stainless steel alloys are more

resistant to stress corrosion cracking under thermal insulation than their similar stainless

steel alloys previously used for offshore applications, but they are more expensive [40].

As was mentioned in the first chapter, stainless steel alloys on offshore facilities under

thermal insulation are extremely susceptible to stress corrosion cracking. It is because of

this reason that the oil and gas industry during the last few years has been using this latest

development in the types of stainless steels for offshore piping systems, pressure vessels

and downhole tubing [4].

71

4. CORROSION UNDER INSULATION

Corrosion under insulation is known as the deterioration of piping, pressure vessels or

any structure or equipment due to the ingress of water and contaminants into the

insulation and fireproofing materials, resulting in costly repairs and maintenance

procedures as well as loss of production during the associated shutdown period [41].

Corrosion problems may represent 60% of a maintenance budget for the upstream oil

and gas industry. In the year 1950 Dr. H. Uhlig made a study about the costs of corrosion

in the United States of America (USA) based on national expenditure on corrosion

protection measures where he estimated costs as much as 2.1% of gross national product.

In the year 1998 similar studies were developed in the United States of America (USA)

by CC Technologies in collaboration with the National Association of Corrosion

Engineers International (NACE), which estimated costs of $276 billion or 3.1% of gross

national product [42].

The corrosion costs related to oil and gas exploration and production in the USA

reached $1.36 billion in 1998. From the standpoint of cost of corrosion per barrel of oil

equivalent produced, it represented $0.45 (4 %) of the cost of production of a barrel of oil

during the year 1998 [42]. Corrosion under insulation has been one of the principal

concerns for the offshore and chemical industries since 1970 when the oil crisis caused

the increase of energy cost and the use of more insulation systems at lower operational

temperatures [34]. In some cases, corrosion under insulation may represent more than one

third of the corrosion failures and near failures in the chemical and offshore industries

[42]. In September 2003, a study made by Exxon Mobile Chemical indicated that the

main cause of leaks in the chemical and refining industries is attributed to corrosion

under insulation and 81 percent of piping leaks were found in diameters smaller than 4

inches [3].

72

The majority of offshore platforms have a design life of 25 years with a potential life

extension of another 20 years. Corrosion under insulation is an inevitable threat to

offshore facilities, the environment and personnel, especially to older structures that have

been more than 10 years in service [42].

An investigation of insulation systems based on several major industrial plants

pointed out that approximately 60% of all insulation systems with over 10 years in

service had moisture within the insulation [43]. Experience has revealed that as the time

passes, jackets and weather barriers lose their capacity to protect the insulation from

outdoor conditions and thereby insulation gets wet. Water, oxygen, and other corrosive

contaminants are able to reach the insulated metal, therefore severe corrosion may occur

[4].

Any type of insulated equipment operating in the temperature range -4°C to 150°C is

at the greatest risk to be affected by corrosion. However, carbon steel and 300 series

stainless steels are the most common materials that fail due to corrosion under insulation.

Carbon steels are vulnerable to general corrosion and pitting, while stainless steels are

susceptible to stress corrosion cracking and localized corrosion, especially in the presence

of chloride ions [41]. Chapter one provides a comprehensive description of the corrosion

mechanism of these forms of corrosion that are frequently found under insulation

systems.

4.1 Corrosion Under Insulation Mechanism

The reason steels that are insulated corrode is because once moisture and corrosive

agents find a way to penetrate weather barriers and jacketing systems, the insulation

provides an annular space where the corrosive agents can be retained for a long period of

time. Consequently, corrosion processes are initiated on the insulated metal surface and

73

unexpected and sudden failure may occur [44]. Figure 4.1 shows a carbon steel storage

tank that failed due to wet corrosive conditions under the insulation.

Figure 4.1: Corrosion under insulation near the bottom part of a carbon steel storage

tank [45]

The root cause of corrosion under insulation is the presence of aerated water beneath

insulation. Additional factors such as temperature and contaminants present in the water

play the principal role in determining the extent of the corrosion on the attacked metal

surface. Some insulation materials like polyurethane foams and calcium silicate contain

different amounts of chloride, fluoride, bromide and sodium ions that when moisture and

water enter the insulation, they are leached from the material. Consequently solutions

with low pH level may form, resulting in increased corrosion rates under insulation

systems [27].

74

As was mentioned in the first chapter, corrosion is a natural process in metals trying

to return to their original and natural state, the oxidized state [5]. Corrosion will occur on

offshore facilities if the four components of a corrosion cell are present: the anode, the

cathode, the metallic path and the electrolyte. Usually, on insulated equipment, the only

component that is missing is the electrolyte or water in any of its forms. In the absence of

moisture or water, metals corrode at a negligible rate. Therefore the first line of defense

against corrosion under insulation is weather barriers and jacketing systems that are used

to keep the insulation dry. In practice, avoiding the entrance of water in insulations is not

always feasible. Weather barriers, sealant materials and caulking compounds break down

during the life cycle of the equipment due to mechanical abuse, vibration, sunlight and

many other external factors that will allow the undesirable presence of water and

moisture between the metal surface and the insulation [27].

The marine environment is the principal source of water and chlorides in insulation

systems and the least controllable. Water spray resulting from wave action as well as

precipitation supplies the major amount of water over insulation systems. Some

additional water sources that contribute to this problem are: drift from cooling towers,

testing of fire protection system, wash downs, moisture in air, coastal fog, ice, and

process leaks [27]. Moisture may also be present in the insulation material itself.

As water penetrates the insulation system, it condenses and wets the metal surface. If

the temperature of the metal surface is too hot, then the water is vaporized and diffuses

within the insulation material where it may recondense. Since weather and vapor barriers

are applied over the warm side of insulation to prevent the ingress of water, they also act

as an obstruction to water and moisture to leave the insulation system [45].

75

4.2 Factors Promoting Corrosion Under Insulation

The principal factor in preventing corrosion under insulation is to keep water from

reaching the metal surface. Absorption capacity of insulation materials plays a vital role

in this case. When insulation becomes wet, it promotes the conditions for corrosion to

start on the insulated equipment [46]. Nowadays there is not a perfect insulation system

that will maintain its integrity during the life cycle of offshore structures and associated

facilities. The following section gives a detailed description of the factors that in

combination with water ingress contribute to corrosion processes under insulated

equipment.

4.2.1 Marine Environment

Sea water covers more than two third of the surface of the earth. Offshore

structures and associated topside facilities have always had to withstand the aggressive

and corrosive effect of the marine environment. The sea water and the air above it contain

chloride ions and other components that are highly soluble in water. When they are

deposited on the metal surface, they can cause an increase of the electrical conductivity

of the electrolyte. Consequently the rate of corrosion is accelerated [35]. Figure 4.2

illustrates the relative rate of metal loss in three different corrosive environments, where

the marine environment has the greatest corrosive influence.

76

Figure 4.2: Metal loss of carbon steel in three different environments [5]

Chlorides are responsible for the sea water salinity. Sodium chloride is the most

common type of chloride salt found in corrosion under insulation case histories.

Concentrations as little as 1000 parts per million of chloride have been found to produce

stress corrosion cracking of austenitic stainless steel [27].The salt content of the oceans

can be considered to be constant and normally it is in the range of 33 to 38 parts per

thousand. The universal value used for open sea water is 35 parts per thousand. This is its

salinity and is typically expressed with the symbol: S°/00, which represents the weight in

grams of dry salts contained in 1000 grams of sea water. Since the sea water has almost

constant proportions for the principal constituents, the concentration in grams per

Kilograms of the nine major ions can be obtained, if the salinity is known. Table 4.1

shows the composition of a sea water sample with a salinity of 35 parts per thousand

[35].

77

Table 4.1: Major ions in solution in an open sea water at S°/00 = 35.0 [35]

Ions (g/kg) Total salts 35.1 Sodium 10.77 Magnesium 1.30 Calcium 0.409 Potassium 0.338 Strontium 0.010 Chloride 19.37 Sulphate at SO4 2.71 Bromide 0.065 Boric Acid as H3BO3 0.026

On offshore facilities, the rate of deterioration of steel equipment due to a failed

insulation system will be influenced by the amount of salt particles that reach the metal

surface. They are normally transported and deposited over insulation systems by wind,

rain, and water spray from the waves. The hydroscopic characteristic of salt particles

permits the absorption of water vapor and the formation of a liquid film on the metal

surface [48]. If the temperature of the insulated equipment is hot enough, when moisture,

water and the dissolved salts diffuse into the insulation hardware, the water will

evaporate and the salts will be deposited on the metal surface. Further water ingress and

evaporation cycles will increase the concentration of salts. Therefore chloride

concentration need not be high in the air or in the sea water to accelerate the corrosion

rate on the underlying equipment [27].

4.2.2 Air Pollutants

Corrosion rates under insulation materials are also affected by the presence of

specific pollutants in air such as sulfur dioxide (SO2) that in combination with

atmospheric moisture is converted to sulfuric and sulfurous acid, producing acid rain.

78

Oxygen and the acid water droplets may enter the insulation and consequently can

accelerate the rate of corrosion on the metal surface [27].

Industrial activity is one of the principal sources of air contaminants; particularly

power generation plants that, by burning fossil fuels, produce a substantial amount of

sulfur dioxide and hydrogen sulfide [49].

In Nova Scotia, the burning of coal from the electric power sector produces the

greatest levels of sulfur dioxide in the province that is known as one of the principal

contributors of acid rain. During the winter season, air pollution is increased due to the

combustion of oil and coal for heating purpose [5].

Municipal incinerators and coal burning power plants are also a source of chloride

emissions to the atmosphere. The chlorine content of most coals ranges from 0.09 to 0.15

%, but there has been found coals with chlorine content as high as 0.7 %. Hydrogen

chloride resulting from the combustion of these coals can easily dissolve in water and

create an acidic solution that will accelerate the corrosiveness of water under insulation

systems [49].

Hydrogen chloride and gaseous chlorine are more likely to have a higher

corrosive effect to most metals than hydrogen sulfide or chloride salt ions from the salt

spray. Nitrogen oxide also tends to accelerate the corrosion rates. Emission of nitrogen

compounds in the form of NOx has been found to have increased in comparison to SO2

levels [49].

Acid rain represents a major problem in the eastern provinces of Canada. In 2005,

the provinces of Ontario, Nova Scotia and Quebec developed tighter regulations for

major acid rain-causing emission sources. The Air Quality Regulations of Nova Scotia

establish a 25 % reduction in the SO2 emission for Nova Scotia Power Inc. beginning in

79

2005 and a further 25 % reduction in 2010. Since 1980, Canada has been reducing its SO2

emissions. In 2004, the SO2 emissions were reduced about 28 % from the national cap of

3.2 million tonnes. Figure 4.3 shows the Canadian SO2 emission from acid rain sources

between the years 1980 and 2004 [50].

Figure 4.3: Canadian SO2 emission from acid rain sources, 1980-2004 [50]

There may be also, in addition to the general air pollutants, other specific air

contaminants that may be emitted in certain areas from different industry sectors that can

result in a higher corrosive effect than the general atmospheric pollutants [49].

80

4.2.3 pH Effect

The chemical composition of water can cause severe corrosion under insulation

and unanticipated failures of process systems may occur. Acidic solutions can result in

general and pitting corrosion of carbon steels. Experience has shown that in the case of

stainless steels, the presence of tensile stress, temperatures exceeding 60 °C and low pH

levels of the water can contribute to stress corrosion cracking [51]. Clean rain water has a

pH level near 5.6; however in polluted industrial areas the atmospheric water can reach

levels of pH as low as 3.0. Acid rain is becoming a severe problem and will magnify

corrosion rates if it diffuses into the insulation [52]. Fog droplets can also be of high

acidity. The pH of fog moisture has been found to be as low as 2.2 in areas with high

degree of air pollution [49]. Figure 4.4 shows the effect of pH on the corrosion rate of

iron in aerated water at room temperature.

Figure 4.4: Effect of pH on corrosion of iron in aerated water at room temperature [53]

81

It can be observed in Figure 4.5 that the corrosion rate increases considerably as

the pH falls below 6. In wet insulation, the corrosion rate can be up to 20 times greater

than the corrosion of bare metals exposed to atmospheric conditions. Some insulation

materials as well as sealants and caulking compounds, when wet, produce acidic

solutions due to the water leachable components [53]. The resulting liquid solution can

have pH levels in the rage of 1.7 to 10 depending on the type of insulation material [27].

On the other hand sea water is usually alkaline and the pH of the ocean near the surface,

where the water is at equilibrium with the carbon dioxide of the atmosphere range from

8.1 to 8.3 [35]. Consequently, special consideration must be given to atmospheric

conditions and the type of insulation system to be used in order to protect the offshore

facilities from accelerated corrosion.

Although in the eastern region of Canada the acidity of rain has declined since

1980, the pH of rain is still acid, being 4.6 [54]. As a result, water from atmospheric

precipitation in the east coast of Canada will continue to have an important impact on the

occurrence of corrosion under insulation on offshore facilities. Figure 4.5 shows the five

year mean pH of rain in Canada and United States and where it can be observed the low

levels of pH of rain in the provinces of Nova Scotia, New Brunswick and Newfoundland.

.

82

Figure 4.5: Five year mean pH of rain in Canada and United States [54]

The coastal fog in Nova Scotia and Newfoundland has been found to have greater

concentrations of nitrate and sulfuric acid than those measured in precipitation. At Cape

Forchu (Nova Scotia) and Cape Race (Newfoundland), more than 2000 hours of fog per

year have been reported. In 1993 the average pH of fog at Cape Forchu and Cape Race

was 3.86 and 3.71 respectively, five times lower than the measured pH of rain [55].

83

4.2.4 Environmental Conditions

Atmospheric conditions at the location at which the insulation systems are going

to be used are important factors that need to be considered in order to evaluate their

natural impact on the occurrence of corrosion under insulation on offshore facilities. A

relative humidity of 80 % is required for initiation of atmospheric corrosion in areas

without air pollution. Iron will start to corrode at relative humidities of about 50 % in

polluted areas. The marine environment is considered extremely corrosive due to the

presence of sulphate and chloride ions and the high levels of humidity [49].

Sable Island, situated 300 km southeast of Halifax, Nova Scotia, where offshore

gas production platforms are located, is known to be one of the foggiest places in the

Maritimes. Approximately 127 days per year have at least one hour of fog. The summer

season is the time with the most fog, an average of 22 fog days has been recorded during

the month of July [56].

Because the island is in the path of many storms and tropical cyclones throughout

the summer and fall, the majority of its precipitation is generated by large scale storms

and hurricanes such as Evelyn in 1977 and Juan in 2003. The number of wet days is

almost the same as the number of dry days. The yearly average precipitation and snow is

1372 millimeters (mm), of which 9 % is snowfall [56].

Of all the principal Canadian cities, St. John's located in the province of

Newfoundland and Labrador, is the foggiest city, having an average of 124 fog days next

to Halifax with 122 days. It is also the wettest city with 1514 mm of rain and snowfall

[56].

The heavy precipitation and strong winds in the region of Newfoundland are the

result of the many storms that pass near and over the region. The Hibernia platform

located on the Grand Banks, east southeast of Newfoundland and Labrador is affected by

84

the severe climate conditions of the area. At all times of the year, storms may occur and

affect the offshore structures located in Newfoundland. The frequency and intensity of

storms is greatest between the months of November and March when winter cyclones

bring considerable amount of precipitation [56].

An average of one tropical storm per year, during the last thirty five years has passed

close to Newfoundland and Labrador. One of the most tragic Canadian marine disasters

in the last few decades was on February 15, 1982 when the drilling rig Ocean Ranger

sank on the Grand Banks during the violent weather conditions [56].

The province of Newfoundland and Labrador has the strongest winds of any

province. The annual average wind speed is greater than 20 kilometres per hour (km/h).

The waters on the Grand Banks, where the Hibernia production platform is located, are

among the foggiest in the world. The fog may occur in all seasons, but, it is more

frequent during spring and early summer. Over 160 days of fog per year have been

recorded on the Grand Banks waters. More surprisingly, nearly 206 fog days have been

documented along the southwest coast of the Avalon Peninsula of Newfoundland and

Labrador. Frequently these fog days are accompanied by strong winds. These conditions

are very dangerous for offshore platforms and for shipping vessels, particularly if

icebergs are present [56].

4.2.5 Service Temperature

Service temperature is a key factor promoting the occurrence of corrosion under

insulation. Experiences have shown that carbon steel equipment operating at

temperatures between -4 °C to 150 °C is at the greatest risk of corrosion under insulation.

Austenitic stainless steels are more likely to corrode in the temperature range of 50 °C to

150 °C. Below 50 °C the rate of corrosion is low and failures are not frequent. [44]. The

85

corrosion potential doubles for every 15 to 20 °C increase in temperature between 0 °C

and 100 °C [51].

Generally, corrosion under insulation is mostly found in the temperature range

where water in liquid phase can be present. Water that may bypass the insulation, where

the service temperature of the equipment is below -4 °C, would freeze and the equipment

will remain free of corrosion during the most part of its entire designed life [44].

Particularly this type of equipment that operates under this condition shows corrosion

outside of the insulation, on the metal jacket rather than under the insulation due to the

condensation of the water vapor in the atmospheric air [38].

In the case of equipment operating above 150 °C, corrosion rates tend to decrease,

because water evaporates before it can get to the metal surface. However, failures have

been found even on systems working at or above 370 °C, when weatherproofing is poorly

maintained [38]. Figure 4.6 shows the effect of temperature on steel corrosion in water in

an open system, in a closed system and under thermal insulation [27].

86

Figure 4.6: Effect of temperature on carbon steel corrosion in water [27]

As can be observed in Figure 4.6 in an open system as the temperature increases,

the corrosion rate of carbon steel in aerated water begins to decrease, particularly above

80°C when the amount of oxygen dissolved in solution decreases. Nevertheless, in a

closed system as the water temperature increases, the corrosion rate of carbon steel in

water continues to increase [57]. Actual chemical plant measurements of corrosion rate of

insulated carbon steel prove that the rate increases with temperature in a similar way to

that of a closed system [58]. The corrosion rates from field measurements have been

found to be greater than laboratory rates, due to the existence of salts and dissolved

contaminants in the water [27].

87

4.2.6 Insulation Materials

Insufficient insulation material specifications and application requirements may

cause accelerated corrosion of the insulated equipment and unexpected failures.

Insulation materials with high degree of water absorbency such as calcium silicate and

mineral fiber are more likely to allow corrosion on the underlying metal surface.

Corrosion can be reduced by cautious selection of the insulation material. Inexpensive

materials on an initial cost basis may not be economical on a life cycle basis if they

promote corrosion [27].

In 1993, one of the main North Sea operators insulated a pressure vessel with

mineral fiber on an offshore platform and after 11 months of service a small leak was

observed through the jacket. The insulation was removed and stress corrosion cracking of

the welded seams of the vessel was found. As a consequence, the vessel was repaired and

reinsulated with closed cell cellular glass [59].

Basically, the insulation system that absorbs the least amount of water and dries

most rapidly should represent the greatest protection against corrosion process [27].

Some insulation materials, sealants and adhesives contain water leachable compounds

such as chloride and sulphate that may contribute to corrosion. Experience has confirmed

that insulating materials with chloride content as little as 350 parts per million (ppm)

have caused stress corrosion cracking on stainless steel equipment. Polyisocyanurate

foams, phenolic foams, and polyurethane foams are some examples of insulation

materials that contain considerable amount of leachable chlorides that induce undesirable

corrosion failures [27] .

One example of corrosion failure with polyurethane insulation was an Exxon

insulated hot tank that had severe corrosion due to the acidic condition that was formed

88

as a consequence of the combination of water and halogens in the insulation. The source

of the halogens was the fire retardant used on the insulation [51].

4.2.7 Mechanical Design of Equipment and Insulation Installation

The geometry of equipment and related attachments has an important effect on

corrosion under insulation. In general, equipment that has an irregular configuration and

has a considerably number of attachments such as brackets, support rings, pressure and

temperature gauge devices, is more likely to have corrosion problems. The life of

insulated systems can be considerably extended by limiting the amount of attachments,

protrusions and supports associated with the equipment [44]. Sealants and caulking

compounds used to seal protrusion through insulation tend to age quickly and may fail

within 3 to 5 years. As a consequence, water can bypass the insulation, settle for a long

period of time on the metal surface and start corrosion [60].

A poorly installed insulation system has an important influence on the

performance of insulation systems and promotes corrosion of the underlying steel

surface. Figure 4.7 shows a poorly finished jacketing system where caulking compound

was not used to seal the piping attachments providing easy water access. A common

installation error is on horizontal sections where the lap section of weather barriers is

installed near the bottom or top of piping rather than to the sides, thereby increasing the

risk of water ingress [3].

89

Figure 4.7: Unsealed insulation penetration where water can enter the insulation

4.2.8 Mechanical Damage

Because corrosion can not occur in the absence of water, an insulation system that

suffers mechanical damage, especially caulking compounds and weather barriers, may

allow the easy entrance of water into the system. As a result, corrosion can start on the

underlying equipment and unexpected failures could happen.

A typical case of mechanical abuse is personnel walking over insulated piping

systems or climbing over vessels due to routine maintenance work. An oil refinery in the

Northeast of United States had to rebuild an insulated carbon steel vessel as a

consequence of repetitive climbing of maintenance workers who needed to attain the top

of the vessel. The aluminum jacketing was deformed, allowing water to ingress the

insulation system every time it rained. Consequently, corrosion under insulation occurred

on the metal surface of the vessel and caused costly repairs and new insulation had to be

90

installed. Holes in the jacketing system as is illustrated on Figure 4.8 are common source

of water entrance and usually are not noticed until the insulation has been wet enough to

cause severe corrosion problems [3].

Figure 4.8: Mechanical damage of jacketing systems [3]

This issue often results in unplanned shutdowns, loss of production and

unscheduled replacement or repair of equipment. Frequent inspection programs as well as

team effort is the only solution to identifying breaks in weather barriers and sealing

systems together with promptly associated repairs that will reduce the risk of corrosion

under insulation.

91

4.3 Susceptible Places

Identifying potential areas where corrosion under insulation may occur is an

important aspect for corrosion monitoring programs in order to prevent and reduce

failures on the process systems. Some equipment and places on offshore facilities are

more susceptible to corrosion under insulation than others. The following is a list of those

areas that are at higher risk where special considerations must be taken during inspection

programs [61].

• Areas with low weatherproofing or exposure to deluge systems, mist spray from

cooling towers or from wave action that continually wets weather barrier and

jacketing systems [61].

• Carbon steel piping systems and vessels operating in the temperature range -4°C

to 120°C. Equipment that normally operates in intermittent service temperatures,

between cool and warm cycles, that cause continuous condensation and re-

evaporation of moisture, are at greatest risk [61].

• Equipment and piping systems with attachments that protrude through insulation

such as pipe supports, ladder brackets and nozzle extensions [61].

• Vibrating equipment and piping systems that may damage the jacketing system

[61]

• Systems with irregular shapes that are difficult to insulate [27].

• Horizontal surfaces or bottoms of vertical piping runs where water may be

retained [27].

92

• Insulated equipment with wicking type insulation materials such as mineral fiber

and calcium silicate that can hold considerable amount of water [27].

• Austenitic stainless steel vessels and piping systems operating in the temperature

range 60 °C to 204 °C are susceptible to stress corrosion cracking under insulation

systems [61].

• Termination or joint sections of insulation where weather barriers may break

down and allow water to enter the insulation [61].

• Missing or damaged jacketing systems and caulking compounds that have dried

enough to crack or to detach from the insulation [61].

• Areas where insulation plugs have been removed to permit inspections are

susceptible to corrosion under insulation if they are not properly sealed [61].

• Insulation jacketing lap sections installed near the top or bottom of piping systems

receive particular attention due to the potential risk of water intrusion [61].

4.4 Inspection Methods

Corrosion under insulation represents a real threat to the operation of offshore

facilities. The main reason is that the insulation hardware covers the corrosion process

and prevents its detention until it is too late to save the affected metal. Unseen corrosion

can lead to catastrophic failures that can put human life in danger. Unexpected failures

can also cause the release of harmful process products to the environment and cause

costly downtime to offshore production activities [62]

93

Various inspection techniques are commonly used to assess the integrity of

insulated process systems and to ensure the reliable and safe operations of offshore

facilities. Inspection methods can generally be divided into two categories: visual

inspection and nondestructive testing (NDT). Visual inspection consists of removing part

or all the insulation material for assessing the surface condition of piping systems or

equipment, followed by replacing the insulation. However, this method is the most

expensive and also time consuming. Sometimes, it may require the use of additional

inspection techniques such as eddy current or liquid dye penetrant to identify small

cracks on the metal surface [62]

A visual examination without stripping down the insulation can be performed as

an initial inspection phase that will help to identify evidence of corrosion, moisture or

mechanical damage on jacketing systems. Therefore, further investigation and inspection

techniques can be applied to evaluate whether there is corrosion on the underlying metal

surface. All personnel at offshore structures are able to conduct and should help with this

type of visual examination that represents the easiest and least expensive way to evaluate

large insulated areas in a short time and may contribute to recognizing potential corrosion

places on topside process systems [27].

Nowadays there is a variety of nondestructive testing methods available for the

offshore industry to assess the integrity and condition of their systems with minimum

stripping down while the platform is still in production. Historically inspection programs

have been performed during plant shutdowns. However, recent risk based inspections

have been used to establish priorities and predictions of systems that are more likely to

fail together with the evaluation of the consequence of that failure. There is obviously a

financial benefit in applying this approach. However, adopting this method with the use

of nondestructive testing techniques does not always result in full coverage of the

insulated equipment due to the capabilities of existing inspection tools hat may not be

applicable to some particulars systems. A diversity of improved and new NDT has been

94

developed during the past few years to closely meet the need for full surface coverage.

These inspection techniques are designed to be cost effective and at least appropriate for

detecting areas for further evaluation. Some of these new methods are described in the

following section [63].

4.4.1 Pulsed Eddy Current Testing

The pulsed eddy current method is used to measure remaining wall thickness of

the insulated metal. A special coil is placed on top of the insulation which transmits low

frequency eddy currents producing a magnetic field in the steel. As the magnetic field

decay, eddy currents diffuse through the steel wall. When the eddy currents reach the

back wall, they decay more quickly. A receiver coil measures the arrival time at the back

wall, thereby, the metal wall thickness can be obtained. When a change in wall thickness

is deduced, there is indication of the presence of corrosion [63].

Some of the benefits of this type of technique are that it does not require surface

preparation; it is portable and it can survey rapidly large number of regions of wall loss.

The drawbacks of this type of method are that it is affected by adjacent metallic

components; it gives an average of wall thickness over the inspected area; it can not

differentiate between internal or external corrosion and it does not detect cracks or small

pits [64].

4.4.2 Real Time Radiography

Real time radiography consists of an electromagnetic radiation device that

produces X-ray beams which penetrate the insulation system and image the outside wall

of the pipe or vessel through a TV type monitor during the inspection. The new system

uses a C shaped arm as shown in Figure 4.9 to scan the insulated equipment. The X-rays

are generated on one side of the arm and received on the other side. A helmet mounted

95

video system allows the operator to move the C arm with both hands while he can watch

the displayed outside wall on a monitor. One of the disadvantages of the systems is the C

arm. It has had good results in checking pipes with a nominal diameter up to 24 inches.

Another limitation is its use in confined spaces, such as pipe racks, where there is not

enough clearance to place the C arm [62].

Figure 4.9: Real time radiography system [62]

Some of the advantages of the real time radiography system are that the video

type images can be stored for further evaluations; it can cover large areas in a short time

and can detect wet insulation and external corrosion [64]

4.4.3 Magnetostrictive Technology

This relative new technology enables inspection of long segments of pipe by

transmitting elastic or guided waves through the wall of pipes and tubing. A receiving

coil placed at a fixed distance from the transmitting coil detects changes in waves due to

96

variations of wall thickness or geometry. The distance that the waves can travel depends

on the pipe diameter, wall thickness and the amount of general corrosion. If there is a

large area with general corrosion, the distance will be shorter. Figure 4.10 illustrates a

schematic diagram of the magnetostrictive system and associated instrumentation for

piping inspections.

Figure 4.10: Schematic diagram of Magnetostrictive technology [65]

The benefit of this technology is that it allows the inspection of long segments of

pipes in a short time. The principal disadvantage of the system is that it requires the

removal of small sections of insulation to place the sensors that may be poorly sealed

after the inspection allowing the ingress of water. Another drawback is that it is only

effective in straight runs of pipe [64].

97

4.4.4 Infrared System

Infrared technology is used to detect damp spots in the insulation. Areas where

water and moisture have become trapped in the insulation have a detectable temperature

difference between the dry insulation and the wet insulation. Since corrosion under

insulation will occur only with the presence of water and moisture, damp sections have

the possibility to have corrosion under insulation [62]. Infrared, also called thermography

technology does not require surface preparation, it is a portable tool that can survey large

area in a short time and it is very sensitive to detect moisture in the insulation. Because

this technology is used to detect wet insulation, it does not identify corrosion. Therefore

insulation segments need to be removed to assess the condition of the underlying metal

surface and then reinstalled; resulting in a possible source of water ingress if the sections

are poorly sealed.

4.4.5 Neutron Backscatter

The Neutron backscatter system consists of a radioactive source that emits high

energy neutrons into the insulation. It is used to detect wet insulation. If there is water or

moisture in the insulation, the energy of the neutrons will decay. The low energy neutrons

are recorded with a gauge detector. The more water in the insulation, the more neutrons

will be counted. Like the infrared technology, this system only detects wet insulation and

not corrosion. It can survey a large number of areas rapidly and does not need surface

preparation. This technique requires good expertise of the operator to make the

interpretation, because sometimes the results may be affected by fluid level within pipe

[64].

98

4.4.6 Long Range Ultrasonic

The long range ultrasonic system consists of an array of transducers that are

placed over an uninsulated section where guided waves are generated along the pipe to

detect metal loss and flaws. The system permits inspection of pipe section up to 50

metres from the position where the ultrasound signals are transmitted. One of the

principal advantages with this relatively new technique is that it provides a good method

to evaluate areas with limited access such as deck penetrations and pipes on supports.

The main drawbacks of using this system are that it is only effective on straight runs of

pipe and also it enables detection of the position of corrosion but not its extent. Since the

long range ultrasonic method requires removal of a piece of insulation to place the

transducer, the area must be effectively reinsulated and sealed after the inspection in

order to prevent potential water ingress. Finally, although the system is usually reliable

when metal loss is as low as 5 % of the pipe wall cross section, narrow cracks on

stainless steel equipment may not be detected [64].

4.5 Risk Based Inspections

Constantly people are making decisions based on risk. From walking across a

busy street to drilling into deeper offshore reservoirs, every activity involves risk. Risk is

known as the combination of the probability of some event occurring during a time

period of interest and the consequences, generally negative, associated with the event

[66].

The purpose of risk based inspections (RBI) is to establish what incident may

occur as a result of an equipment failure, and the probability of that incident happing. If a

piping system develops a leak due to deterioration of the external wall surface from

corrosion under insulation, a diversity of consequences such as environmental damage or

injuries to personnel and damage of the installations due to ignition of the leakage may

99

occur. The combination of the possibility with the consequences of one or more of these

events occurring will determine the risk to the facility [66].

The most important factor when assessing the risk of a specific event is the extent

and gravity of the consequences that may result from a failure. There are failures that

could happen very frequently but without having a major impact to the environment,

human life or to production. On the other hand, there are failures that may occur

sporadically but with severe consequences, therefore the associated equipment should

require more frequent inspections. The higher the risk of an event to happen, the more

inspection and mitigation actions will be needed in order to reduce the associated risk

[66].

By evaluating the risk of every type of equipment to the operations of an offshore

facility and ranking it on a risk basis, an inspection program can be developed starting

with the areas of highest risk. In order to develop an effective risk based inspection plan,

engineers need to be able to evaluate the risk related to each item of equipment and then

establish the most suitable inspection method for that equipment. The difficulty of risk

calculations is the number of variables that have an effect on the risk. Therefore,

equipment, facilities and systems are usually ranked based on relative risk instead of

calculating an absolute risk value which can be costly and time consuming due to the

numerous uncertainties involved [66].

By setting the priorities and frequencies of inspection, this new generation of risk

based inspections eliminates the previous strategy of calendar based assessment and

maintenance programs that were more dependent on a calendar date rather than the

equipment conditions. Risk management plans focus on improving reliability and

availability of the offshore assets or any type of process system while safeguarding life

and the environment. The RBI approach can provide input into the annual planning and

100

budgeting of an organization by identifying the funds and personnel required to maintain

the operational activities at satisfactory levels of performance and risk [66].

One of the advantages of applying risk based inspections programs is their

flexibility for the reassessment of risks as new inspection results become available. They

can be adjusted and improved according to new data that may provide new understanding

of failure mechanisms and limitations of the available inspection technologies [66].

Risk management approaches represent a new method for interval inspection

setting, understanding that the final purpose of inspection is the reliability and safety of

operating facilities. The main advantage of RBI is that it centers the attention on the

equipment and associated corrosion mechanisms with the highest risk to the facility.

Consequently, reduction of inspection time and cost may be achieved as well as

mitigation of risk with an efficient combination of the appropriate inspection technology

and risk assessments [66].

4.6 Industry Trend

Corrosion under insulation has been a major issue for the oil and gas industry for

decades, particularly since 1970 when more concern about energy conservation led to the

increased use of insulation system to reduce the energy loss associated with the process

equipment.

As stated in the previous section, corrosion under insulation occurs because of the

presence of aerated water between the insulation material and the underlying metal

surface. A careful selection of insulation materials is the first step to reduce the problem.

Nowadays, the oil and gas industry is pursuing the mitigation of the problem of moisture

and water by no longer selecting of calcium silicates and mineral fiber as one of the

insulation materials and is turning almost completely to the use of closed cell cellular

101

glass. This type of insulation material is totally impermeable and exhibits chemically

neutral behavior that helps the prevention of stress corrosion cracking on stainless steels

from the leachable chlorides and other components that the majority of the other

insulation systems contain and thereby produce acid solutions.

In Germany, the DIN 4140 standard suggests the use of closed cell insulation

materials such as cellular glass to reduce the occurrence of corrosion under insulation

systems. Many major North Sea operators after experiencing premature and frequent

failures of piping and pressure vessels that were insulated with mineral fiber, now are

choosing closed cell cellular glass to reinsulate the failed equipment to ensure long

insulation life and to increase the reliability of the systems [58].

This type of insulation material seems to have less incidents of corrosion and is

gaining a good reputation among the oil and gas industry for onshore and offshore

applications. Another insulation material that the offshore sector is turning its attention to

aerogel insulation materials. This relatively new material, as described in the previous

chapter, has outstanding thermal properties due to its nanometre pore structure.

Additionally, its hydrophobic property allows the prevention of water and moisture

diffusion into the insulation; therefore, they represent an attractive solution to corrosion

problems on offshore facilities.

Another approach of the oil and gas industry in combating the corrosion under

insulation problem is the replacement of insulation used for personnel protection with

wire cage systems. In this way, the use of insulation is minimized resulting in reduction

of corrosion risks on equipment.

Companies in Europe have been using for the past few years an aluminum foil

wrapping technique to protect stainless steel pipes from stress corrosion cracking. In

North America, this method has not been widely accepted. The aluminum foil provides

102

an obstacle to water and chloride deposition on the stainless steel and also offers cathodic

protection by being more susceptible to corrosion [45].

The oil and gas industry has started utilizing more duplex stainless steel alloys

rather than carbon steel for the production and processing facilities in order to mitigate

the risk of corrosion under insulation. The duplex stainless steel alloys have higher

chromium levels than the austenitic stainless steel alloys and have been found to be more

resistant to stress corrosion cracking under insulation. The Tiffany platform, operated by

ENI since 1993, is an example of this corrosion mitigation approach. It is a fixed

platform that contains many processing facilities made of duplex stainless steels [42].

Inspections are now focused on corrosion risk assessments rather than

chronologically based general inspections. This has led to the identification and

prioritization of areas of concern that have higher risk of corrosion and need to be

frequently inspected. By implementing risk based schemes, the companies have been able

to reduce operational spending, and improve the reliability and safety of the offshore and

onshore process systems. Risk based management approaches are combined with the

application of more non-intrusive inspection techniques with regular visual assessments

of the condition of jackets and weather barriers to reduce the higher cost of removing and

reinstalling insulation systems. The main difference between the RBI approach and the

previous inspection and maintenance programs is that it allows the inspection intervals to

be changed as new data and results from inspections become available, in contrast to

fixed inspection intervals traditionally performed [42].

A thermal spray aluminum technique is one of the latest coating systems that have

been used during the last few years to prevent corrosion under insulation. It seems to be

the best type of coating system for severe conditions where organic coatings have failed.

It protects the metal surface of equipment by acting as a sacrificial anode and at the same

as a barrier coating. An important petrochemical company has shown large savings in its

103

corrosion control programs by increasing the use of thermal spray aluminum [45]. In the

following section, a general description of coating systems that are applied under

insulation materials is provided including the thermal spray aluminum system.

104

5. PROTECTIVE COATINGS

Protective coatings represent one of the best options to prevent the electrolyte

from reaching the metal surface and thereby reducing the occurrence of corrosion under

insulation. The oil and gas industry has successfully used coating systems for many years

[46]. However, some coatings that have demonstrated good performance for atmospheric

service, have given unsuccessful results under insulation materials such as the case of

inorganic zinc coatings [27].

Coating a metal having good mechanical properties is usually a better cost

efficient approach than selecting a more expensive and corrosion resistant steel without

applying protective coatings [8]. In order to protect against corrosion, the main

characteristics for coatings used under insulation are good cohesion and adhesion,

weathering, resistance to the temperature to which they will be exposed and their

compatibility with the insulating material. The coating properties, application procedures

and surface preparation will determine the corrosion resistance provided by coatings [60].

Among these factors, surface preparation is the most important feature in order to achieve

good corrosion protection of the equipment, even more vital than the properties of the

coating itself [8].

Normally, protective coatings are designed for stainless and carbon steels. The

average life cycle of a coating system is typically between 5 to 13 years. When they are

properly applied and selected, they can last up to 20 years [45].

The thickness of a coating is an important factor in a coating system. The majority

of the materials have limits to the acceptable thickness. If it is too thick, the coating may

not adhere to the metal surface. In contrast, if the coating applied is too thin, it will not

provide an effective barrier; thereby the metal will corrode in the presence of water and

moisture under the insulation [4].

105

5.1 Paint Coatings

Painting of metals is the most common and the oldest technique used to prevent

corrosion. Nowadays, there are a variety of paint coatings available in the market with

different application methods to choose from. Some examples are the liquid applied

coatings such as epoxies, urethanes and polyureas that are suitable for application by

spray or brush [67].

Paints basically are made of solid particles, called the pigment, which are mixed

with resins, solvents and plasticizers, called the vehicle. Thinners and solvents are added

to control the viscosity and achieve appropriate application properties [35]. The resins are

used as a binder for the pigments to make a homogeneous film. The plasticizers give

flexibility, toughness, and extendibility to coatings [4]. In general, corrosion protection of

steels by the application of paint coatings requires more than a single coat of paint.

Frequently, protective coatings consist of three or more coats of paint, each having

different properties and functions [35]. Paint systems for atmospheric applications are

normally composed of two or three coats of paint. These are categorized as priming coat,

undercoat or intermediate coat and top or finishing coat [4].

The priming coat is the first element applied to the metal surface to be protected.

The primer is considered as the most important component of a coating system. It

provides an effective bond to the metal surface and also to the subsequent coat. The

additional function of primers is their corrosion property. Depending on their chemical

composition, they may act as barriers to water and chemicals, as sacrificial anodes to

protect the underlying steel when the coating is damaged or as corrosion inhibitors [4].

Some priming coats contain corrosion inhibiting pigments. These pigments form

an alkaline solution at the substrate surface in the presence of water to suppress the

anodic or the cathodic reaction [68]. Primers should have an adequate thickness to cover

106

the asperities of the surface entirely. Sometimes when equipment and structures are

manufactured, the time to get to their final destination could be weeks or even months;

therefore, priming coats are usually applied at the point of manufacture to protect the

equipment from corrosion [4].

The undercoats are applied essentially to increase the thickness of the coating.

They are formulated to enhance the resistance to chemicals and moisture vapor transfer

of the entire system. Intermediate coats represent an important part of coating systems

intended to be used in severe environments like on offshore facilities. Adhesion to the

primer is an obligatory requirement to keep the integrity of the system [35].

Finishing coats represent the first line of defense against the electrolyte that may

be formed under the insulation. They are fabricated with similar properties to the

intermediate coat to withstand the corrosive environment that they may be subjected to.

Usually topcoats have a lower pigment to vehicle ratio and are of a different color than

the undercoat in order to assess the extent of coverage [4].

Weather conditions influence the performance of coatings during their

application. A temperature of 21 °C and a relative humidity within the range of 50 and 60

% are considered the proper application conditions for most coatings [9]. For site

application, the working conditions can be controlled by the use of covers to reduce the

flow of air and moisture into the working area. Most of the time the painting periods on

offshore structures and other outdoor applications are scheduled to be during the less

humid months of the year [35]. In the case of the East Coast of Canada, where there is at

least one hour of fog for more than 100 days per year, the suitable conditions for painting

are restricted to specific months of the year.

On offshore structures, salt droplets represent an additional difficulty for field

application. They can cause adhesion problems of coatings to the metal surface and

107

between the coats of paint. Chloride salts promote the formation of moisture over the

surface to be coated even at low relative humidities of about 40%. Because of the severe

and uncontrollable marine conditions, the life and performance of coating systems may

be lower than those applied on land and under better conditions [35].

There are three standard methods that are commonly used for field applications:

rolling, brushing and spraying. Additional methods are usually employed in the working

area of the coating companies. The labor cost associated with any type of work is higher

on offshore structures than doing the same work on land; special consideration must be

taken when selecting the type of application method of coating systems. Table 5.1 shows

the average covered area in a working day, based on field experiences, that an operator

would be able to paint using different methods.

Table 5.1: Paint coatings application coverage rates [35]

Method Area covered/ day (m2)

Brush 100

Roller 200 -400

Air spray 400 -800

Airless spray 800 - 1200

Liquid epoxies are frequently used for coating pipes. They are composed of two

different materials that are mixed just before use. They can be applied by brush or spray.

These paints polymerize by the chemical reaction within the material itself that result

from the mixing of the two components. Special consideration must be given to the

mixture. If epoxies are not mixed in the proper ratio, they do not cure well, resulting in a

poor quality coating [46].

108

Phenolic epoxies are frequently used for high temperature applications up to

149°C. Urethanes and polyureas are excellent coatings for cold service temperature

applications. Most of urethanes are recommended to be used at temperatures below 66°C.

Moisture can affect the quality of urethane coatings, particularly during their application.

Experiences have shown good results with moisture-cure urethanes in cases where

moisture is a problem [46].

Coal tar or asphalt based materials do not require special treatment before their

application. They can simply be applied by paint glove or brush. Surface preparation does

not represent an important element for these materials as it is for many other coatings.

They adhere well to the metal surface and are an excellent choice for irregular shape

applications. The principal drawback of this type of coatings is the recommended service

temperature at which they can be used. They may become too soft and may lose their

adhesion property to the metal at temperatures higher than 49°C. On the other hand, at

temperatures below -18 °C, some of theses coatings may become less flexible [46].

5.2 Metallic Coatings

Metallic coatings constitute the other type of coating systems that are available in

the market. When applied, they can be cathodic or anodic to the substrate metal. In the

case of cathodic, the coating must be free of pores or scratches to prevent water from

reaching the underlying metal or galvanic corrosion will occur. An anodic coating to steel

protects equipment and structures acting as a barrier and at the same time as a sacrificial

coat in the presence of the electrolyte [8].

Sacrificial coatings which corrode before the metal substrate include aluminum,

zinc and cadmium. If the anodic coating has a defect or is damaged, it will still protect

the underlying metal since it is the coating that deteriorates. Corrosion of the substrate

109

can occur but at a very low rate. Figure 5.1 illustrates the sacrificial protection offered by

a zinc coating to a steel substrate in the existence of the electrolyte [69]

Figure 5.1: Schematic representation of sacrificial zinc coating over a steel surface at a void [69]

There are many methods available to apply metallic coatings to steel structures

and equipment. The most frequently used are hot-dipping, thermal spraying and

electroplating. Hot-dipping is the oldest and the simplest technique of applying metallic

coatings. It is widely employed for coating carbon steels. This method is limited to

coatings for low melting metals such as aluminum, lead, zinc and tin. The components

are dipped into a bath of molten metal. The coating is produced by straight reaction

between the molten metal and the steel to be coated [35].

Thermal spraying coatings consist of melting a metal, in the form of wire or

powder, by gas combustion or an electric arc using an especially designed gun. The

110

molten particles are propelled to the surface to be coated by compressed air or other gas.

Aluminum is the most common type of metal widely applied by thermal spraying in the

petrochemical and offshore industry, particularly for corrosion protection of insulated

equipment [45].

Electric arc spraying is applied by creating an electric arc at the tips of two

aluminum metal wires. As the metal melts, pressurized air is used to project metal

droplets on to the steel surface. The recommended operating temperature range for this

type of metallic coating is from -45 °C to 538 °C [70]. The main disadvantage using

aluminum as a metallic coating is its non ferro-magnetic characteristic that restricts the

use of most of the inspection tools for corrosion detection [71].

Electroplating is comparable to the corrosion process. Two metals, one acting as

an anode and the other as a cathode are immersed in a bath containing an electrolyte. The

coating metal that can be zinc, nickel, cadmium or chromium is the anode and the steel to

be plated is the cathode. The electrolyte consists of complex solutions that usually

contain salts and other compounds. Direct current is employed in order to plate the

metallic coating to the metal surface [35].

5.3 Surface Preparation

Surface preparation is the most critical part of coating systems. A poorly prepared

surface will reduce the life and corrosion protection of coatings. Near 75 % of coating

failures can be attributed to inadequate surface preparation [68]. The purpose is to

provide a proper anchor pattern for coatings to adhere to the substrate by removing mill

scale, oil, grease, corrosion product, salt ions, or any other contaminants that may be on

the metal surface. Nowadays, there are many types of mechanical and chemical

treatments for surface preparation such as blasting, wire brushing, caustic cleaning, and

acid pickling [72].

111

Blasting with sand or any other dry abrasive material is an excellent method to

eliminate the majority of contaminants, but it does not remove salts, oil or grease.

Therefore, before blasting an additional cleaning method has to be used if oil, grease or

salt films are on the metal surface [46].

The type of the surface preparation method to be applied is determined by the

type of surface to be coated and the coating to be used. Blasting is frequently used on

new carbon steels. On the other hand, corroded equipment may have chlorides that must

be removed before blasting. Stainless steel surfaces are usually cleaned using grinding

disks, brushes and non carbon blast materials. Experience has shown that the carbon in

some blast materials can cause corrosion problem in certain types of stainless steel [46].

In metal spraying, a roughened surface is needed to provide a suitable anchor

pattern to which the coating will adhere. Blasting with angular grit is one of the methods

commonly used to create the desired pre-coating characteristics on the metal surface [5].

5.4 Failure Mechanism

Coating systems can fail due to a variety of reasons that if not considered during

the design phase and application procedure, their performance and life will be

dramatically decreased. Causes of failure can be related to the coating itself, but most of

the time, environmental conditions and improper surface preparation are the principal

reasons for failures [68]. A brief description of some of the typical coating failure

mechanisms are as follows:

• Delamination or loss of adhesion occurs when surface contaminants such as salts,

mill scale, oil or smooth surfaces create bonding problems of coatings to the

substrate or between paint coats [5].

112

• Cracking or breaks in the coating is another common type of failure caused by

stresses in the coating film. These stresses which can be produced by moisture

absorption, thermal expansion of the metal surface, or the thermal expansion of

the coating itself are greater than the cohesive strength of the coating [5].

• Excessive thinning, incorrect mixing ratio or poor application technique produces

unsatisfactory protection of the substrate and can shorten the life of the coating

systems. Improper coating thickness and discontinuities in the coating film are

some of the consequences that can result from an inadequate application method

[5].

• Equipment geometry and design also contribute to coating failures. Areas such as

sharp edges, bolts, lap joints and welds are usually difficult to coat resulting in

localized corrosion problems [4].

• Peeling occurs when the coating thickness is greater than that recommended by

the manufacturer, causing adhesion problems between coats or to the substrate. In

this case, the cohesive forces within the coating are higher than the adhesive

strength that allows the coating to adhere to the surface [4].

Coating failures can be reduced by employing effective application procedures and by

achieving a clean and good anchor pattern on the surface to be protected to which the

coating will perfectly adhere and will be able to provide excellent corrosion protection

and a barrier to corrosive solutions that may be trapped under insulation systems.

5.5 Industry Trend

Nowadays, the oil and gas industry has stopped using inorganic zinc coatings

under insulation systems due to unsatisfactory experiences. On the other hand thermal

113

spray aluminum coatings have demonstrated successful results in marine and high

temperature environments. It seems to be the best type of coating system for corrosion

protection under insulation where organic coatings have failed. It protects the metal

surface of equipment by acting as a sacrificial anode and at the same as a barrier to water

and corrosive solutions that may bypass the insulation [45].

Additionally, in an effort of reducing the risk of stress corrosion cracking on

stainless steel equipment, the industry is cautiously selecting coating systems that, under

service conditions, will not release chlorides or other halides [27]. Aluminum foil

wrapping has been extensively used in Europe on stainless steel pipes as a method to

prevent stress corrosion cracking, but it has not been broadly accepted in North America.

Normally a 0.1 millimetre aluminum foil is used to cover pipes. The aluminum foil like

the thermal spray aluminum coatings serves as a barrier that stops the salt ions and

corrosive electrolytes from reaching the stainless steel and also acts as a sacrificial anode

by preferentially undergoing corrosion. This technique depends on good jacketing

systems and needs minimum surface preparation [45].

114

6. CASE STUDIES

Corrosion under insulation is and has been a major problem for more than 50

years for the oil and gas industry. Many studies and research have been implemented in

order to understand the factors that promote the occurrence of corrosion under insulation

and also to reduce the risk of unexpected catastrophic failures during the life cycle of the

assets of a company.

Carbon steels and austenitic stainless steels have been the alloys of preference for

offshore and onshore refining and production facilities during the last few decades. As

was mentioned on the previous chapters, carbon steels commonly suffer general

corrosion or pitting corrosion under insulation systems, while austenitic stainless steels

are affected most of the time by stress corrosion cracking or pitting corrosion.

Many papers and real experiences have been published about the hidden danger of

corrosion under insulation. In this chapter, some real experiences and studies are

described in order to give a practical perspective of this persistent threat for the oil and

gas industry.

The first case is of an accelerated study of the corrosion performance of carbon

steel under various classes of insulation in a chemical plant located in Houston, Texas.

Corrosion of carbon steel under insulation depends on a variety of factors such as

moisture, service temperature, type of coating system and the insulation itself. In general,

the insulation material that absorbs the greater quantity of water and moisture is the one

with a higher effect on the corrosion rates of carbon steel. The accelerated study

consisted of twelve insulation materials installed on a carbon steel pipe exposed to the

atmosphere and subjected to hot and cold cycles for a period of one year [73].

115

The carbon steel pipe was a 7.62 centimetres (3 inches) pipe and the twelve types

of insulation materials were approximately 0.6 metres long. An aluminum weather barrier

was used to wrap the insulation, but the end sections were left open. The insulation

samples were installed with a separation of approximately 0.3 metres from each other.

Figure 6.1 shows the configuration of the tested pipe with the associated insulation

samples. The steel pipe was sandblasted and painted with an epoxy – phenolic paint

covering about one fourth of the pipe surface. In order to expose the pipe to hot and cold

cycles, seventy pound steam was run through the pipe once a week for 15 minutes [73].

Figure 6.1: Carbon steel pipe and insulation samples installed on the pipe

A number of holes were made in the weather barrier after the first three months of

the test. This was deemed necessary because rain fell only 14 days and very little

corrosion was found when the pieces of insulation were removed in order to assess the

116

external surface of the carbon steel pipe. During the following months, 0.24 liters of

untreated water were poured into the holes of each insulation sample twice a week when

it did not rain in order to accelerate the test [73].

The results of the test showed that the bare pipe between the insulation samples

corroded at a rate of about 1.27 millimeters per year. It was also discovered that the

corrosion rate where the holes were punched through the weather barrier was almost the

same as that on the uninsulated pipe. The corrosion rate under the edge of the insulation

was virtually as severe as that of the bare steel. Corrosion under the insulation pieces was

found to be worse along the bottom of the pipe than on top or the sides. Table 6.1 lists

the results of each type of insulation that was tested in increasing order of the effect on

the corrosion rates of the carbon steel pipe.

117

Table 6.1: Results of the corrosion test

Rank Insulation Sample Comments

1 Expanded perlite (1) Line of pitting 2.5 to 5.0 centimetres wide on bottom

2 Expanded perlite (2) Line of pitting 2.5 to 5.0 centimetres wide on bottom

3 Calcium silicate (4)

4 Calcium silicate (3)

5 Calcium silicate (2)

6 Calcium silicate (1)

Rank items 3, 4, 5 and 6 are about the same in performance. Insulation very heavy with water when removed.

7 Fibrous glass More pitting along bottom and edges than calcium silicates.

8 Expanded perlite baked (1)

9 Expanded perlite baked (2)

Insulation fell apart easily. Much more pitting near the edges. Some more pitting underneath.

10 Polyurethane foam Only one where pitting was fairly uniform all around the pipe. Very little advanced corrosion under the edges

11 Cellular glass Corrosion in the middle about as bad as that near the edges

12 Mineral wool Some insulation stuck to pipe

The two pieces of expanded perlite demonstrated the best performance of the

effect on the corrosion rates. They produced the lowest corrosion rates on the carbon steel

pipe followed by the calcium silicate insulation samples. The worst deterioration was

found under the non-absorbent cellular glass and the mineral wool. The sections of the

pipe that were coated with epoxy – phenolic paint did not corrode during the one year

period of the test. Although the expanded perlite gave the best result, corrosion rates did

not vary appreciably under the different types of insulation [73]. It can be mentioned that

none of the insulation material is an excellent choice to mitigate corrosion under

118

insulation as long as breaks or damage of the weather barriers exist that will allow water

and moisture to reach the external metal surface of equipment. However, the combination

of nonabsorbent insulation such as cellular glass and a good and maintained weather

barrier during the life cycle of offshore facilities may help to reduce the risk of corrosion

problems under insulation systems.

The performance of austenitic stainless steels has also been evaluated for many

years using different types of insulation materials and coatings systems in order to

identify which system gives the best corrosion protection, particularly against stress

corrosion cracking that commonly produce the unexpected failures on stainless steel

equipment used in the oil and gas industry and also in many other types of industries

around the world.

The following case study related to the prevention of stress corrosion cracking of

austenitic stainless steel under insulation was presented by the corrosion engineers of

Imperial Chemical Industries, James Richardson and Trevor Fitzsimmons at San Antonio,

Texas in the symposium on Corrosion of Metals Under Thermal Insulation in 1983.

The research consisted of the evaluation of different paint coatings and aluminum

foil on 304 austenitic stainless steel coiled springs as corrosion preventative systems. As

was mentioned before, after much research about the mechanism of stress corrosion

cracking, now it is widely accepted that three basic conditions must be met for stress

corrosion cracking to occur. These are: the lower operating temperature must be above

60°C, there must be soluble chlorides present on the metal surface and the equipment

must be subjected to tensile stress or plastic strain [74].

Coiled springs were convenient for the test because they provided a structure with

a relative large stressed surface area. A total of five springs were tested. One of them was

left without the application of any paint coating. Silicone alkyd paint, aluminum rich

119

silicone paint and zinc rich epoxy paint were the coatings applied to three of the tested

coiled springs. An additional specimen was wrapped with aluminum foil forming a

cylinder around the spring. The austenitic stainless steel specimens were subjected to full

immersion in boiling saturated calcium chloride solution at 138 °C and sodium chloride

solution at 108 °C for periods of seven days [74].

At the end of the test, paint coatings were removed with solvents, and springs

were dye penetrant inspected using fluorescent ultraviolet lamp in order to identify cracks

on the metal surface. The results of the test are presented in Tables 6.2 and 6.3.

Table 6.2: Occurrence of stress corrosion cracking on coiled 304 spring specimens in

boiling saturated sodium chloride solution at 108 °C [74]

Protection System Total Number of Cracks Protection Efficiency %

None (bare metal) 75 0

Silicone–alkyd paint,

uncured

8 89

Aluminum-rich

silicone paint

8 89

Zinc- rich epoxy

paint

2 97

Aluminum foil 0 100

120

Table 6.3: Occurrence of stress corrosion cracking on coiled 304 spring samples in

boiling saturated calcium chloride solution at 138 °C [74]

Protection System Total Number of Cracks Protection Efficiency %

None (bare metal) 462 0

Silicone–alkyd paint,

cured at 120 °C for 1

hour

21 95

Silicone–alkyd paint,

uncured

26 94

Aluminum foil 0 100

The single coat silicone-alkyd system showed an 89 to 95 % reduction in the

occurrence of cracks compared with the unprotected coil spring. There was little

influence on protection efficiency between the cured and uncured silicone-alkyd paint as

can be observed in Table 6.3. The aluminum filled silicone paint demonstrated the same

corrosion protection efficiency as the metal free paint in the incidence of cracking during

the test in boiling saturated sodium chloride solution at 108 °C. Aluminum foil showed

100 % protection efficiency in both corrosive solutions. However, the good corrosion

protection of the aluminum foil system may be achieved as long as it is properly installed

and the integrity of the foil remains unaltered in order to prevent water and chloride from

reaching the underlying metal surface. In fact, other types of coatings systems may

perform as well as aluminum foil under insulation systems but they all depend upon a

good installation and surface preparation to provide a good anchor pattern for the coating.

Coatings have to be carefully selected in order to use the proper system to be able to

withstand the service temperatures to which the equipment will be subjected, particularly

if hot and cold cycles occur. They need to resist the corrosive environments that may be

formed beneath the insulation systems used on offshore facilities.

121

6.1 Industry Trend

The problem of corrosion beneath insulation has been studied and will continue to

be studied as long as insulation systems are being used. The purpose of the research and

evaluation that the oil and gas industry and other research institutes have been developing

during the last few decades is to reduce the risk of corrosion failures that occur on a daily

basis around the world and also to establish the best corrosion prevention practice when

insulation systems need to be utilized.

During the last few years, the oil and gas industry has been using more duplex

stainless steel and super austenitic stainless steel, particularly on offshore facilities as a

mitigation approach to the costly and persistent problem of corrosion under insulation.

New studies are being proposed and developed in order to evaluate the occurrence and

prevention of stress corrosion cracking on the latest types of stainless steel alloys.

Offshore experiences in the United Kingdom have indicated a variety of service failures

of offshore process and production systems employing duplex stainless steel under

different conditions [75]. Consequently, these doubts will need to be addressed

throughout the implementation of these new alloys for the mitigation of corrosion under

insulation and also the industries will have to establish an accepted consensus, as was

achieved for carbon steel and austenitic stainless steel equipment, about the factors and

service conditions that promote the occurrence of corrosion under insulation on duplex

stainless steels and super austenitic stainless steels under insulation systems.

122

7. DISCUSSION

The development of new offshore oil and gas fields will continue increasing

especially while production from established onshore fields keeps on declining. In

combination with the growth of the offshore oil and gas industry, corrosion under

insulation has been and still is a major concern due to the expanded application of

insulation systems at lower operating temperatures on process and production equipment.

Corrosion under insulation is one of the major causes of equipment outages, unexpected

and catastrophic failures, production losses in refineries and in offshore production and

processing structures.

The reason that a particular insulation is selected and used is to reduce the heat

loss or heat gain through the external surface of equipment such as piping, pressure

vessels and storage tanks with the surrounding environment. Apart from the outstanding

thermal properties that insulation systems provide to offshore facilities, they also create

severe conditions that can cause corrosion problems on the underlying surface. Corrosion

rates under wet insulation can be up to 20 times higher than those found in the

atmosphere.

The principal factors that promote corrosion under insulation are:

(1) The exposure of the insulation system to the corrosive environment

(2) The water and moisture ingress into the insulation hardware.

(3) The corrosion resistance of the construction material of the equipment

Through good design, the exposure of the insulation system to the corrosive

environment can be kept to a minimum. However, since the frequency of the extreme

weather conditions has increased dramatically in the recent years due to the global

warming and other additional factors, the interface between air, water, and insulation

123

system varies widely from the initial design. This interface is the most vulnerable area to

the corrosion problem.

If water can be prevented from reaching the metal surface, corrosion will not

occur. The initial design of equipment combined with the preservation of the integrity of

weather barriers to prevent or reduce the risk of water ingress during the 20 or 40 years of

the life cycle of offshore structures should be one of the priorities for all industries in

order to decrease corrosion failures.

The insulation itself contributes to the problem of corrosion under insulation. It

creates an annular space for water to be retained. The insulation material may absorb or

wick water and also may contain water leachable compounds such as chloride, sulfate,

and fluoride that could increase or accelerate the corrosiveness of the water. Because

corrosion under insulation is the result of water infiltration, the insulation system that

retains or absorbs the least amount of water should represent the best option for corrosion

mitigation. Therefore, special consideration must be given to the selection of insulation

materials that will not be a contributing factor to the occurrence of corrosion. Closed cell

cellular glass insulation materials seem to be a good option for heat conservation and

more importantly for corrosion prevention. They exhibit chemically neutral behavior and

do not absorb water.

Carbon steel and 300 series stainless steels have been the materials of preference

for many years for offshore facilities. During the last few years, duplex stainless steel,

and super austenitic stainless steel are being selected more frequently for offshore

applications due to their improved corrosion resistant properties. By understanding the

types of corrosion that can occur on the commonly used alloys and the service conditions

under which corrosion is more likely to happen, the proper design and selection of

insulation systems and effective risk based inspection programs can be employed to

mitigate the corrosion problem.

124

The environment and atmospheric conditions to which insulation systems will be

subjected represent the principal aspects that promote corrosion and are the least

controllable. As was mentioned before, water is one of the triggering factors for corrosion

beneath insulation. Contaminants in water and in the air such as sulfates and chlorides

can modify the pH of the rain water and thereby corrosion rates may be increased,

particularly if pH levels near 4.0 or below are generated on the underlying metal surface.

Although in the eastern region of Canada the acidity of rain has declined since 1980,

the pH of rain is still acid, having a value of about 4.6. As a result, water from

atmospheric precipitation in the east coast of Canada will continue to have an important

impact on the occurrence of corrosion under insulation on offshore facilities.

The coastal fog in Nova Scotia and Newfoundland has been found to have greater

concentrations of nitrate and sulfuric acid than those measured in precipitation. The pH of

fog has been measured in the last few years at values of about 3.8. Consequently, special

consideration must be given to the installation of weather barriers and also to the

maintenance and prompt repairs of breaks in the weatherproofing where water and

associated contaminants can bypass the insulation and reach the metal surface.

Additionally, sodium chloride is the most prevalent salt found in corrosion beneath

insulation failures. The marine environment that surrounds offshore drilling rigs and

production platforms has an abundant source of this type of salt that, in combination with

moisture, increase the corrosiveness of water. Sodium chloride and other contaminants in

the sea are waterborne and airborne to the jacket surface. Subsequently, if any damage in

the sealants, caulking compounds, or in the jacketing system exists, the salts can enter the

insulation and initiate corrosion.

125

The chloride concentration in the rain, sea water, atmospheric air, fog or even in the

insulation material does not need to be high since the hot temperature of the metal surface

accumulates the chlorides by evaporating the water that enters the insulation until severe

conditions are met leading to corrosion problems.

As long as substantial volumes of pollutants and greenhouse gases, on a global basis,

continue to be emitted into the air, the environment will be subjected to more drastic

changes that will have an effect on the levels of annual precipitation accompanied with

lower pH values of rain and fog. Sea level rising, higher waves and rainstorms may be

more frequent as a consequence of the global warming caused by the greenhouse gases.

Therefore, the characteristics of the environment and the atmospheric conditions of a

particular region will continue to play an important role in the occurrence of corrosion

under insulation on offshore facilities.

Given that is not feasible to exclude water from insulated equipment during the

life cycle of the offshore assets, protective coatings applied prior to insulation systems

have been an effective approach in controlling corrosion. Thermally sprayed aluminum

and aluminum foil wrapping have performed successfully in offshore environments. They

seem to be a good choice to prevent stress corrosion cracking on austenitic stainless steel

systems while experiences have demonstrated that inorganic zinc coatings have given

inadequate corrosion resistance under wet insulation. Paint coatings such as phenolic

epoxies and urethanes are usually considered to protect carbon steel equipment.

More important than the type of coating to be used, surface preparation, the

application requirements and the compatibility with insulation materials represent critical

factors to any coatings system that will have a direct effect on their performance in the

long term.

126

Corrosion under insulation is difficult to detect because the insulating material

masks the affected area until the corrosion has been advanced and it is too late. Removing

insulation sections seems to be the most reliable inspection technique now used to assess

large areas of insulated systems, but at the same time it expensive and time consuming.

Visual inspection for evidence of breaks in jacketing systems and defects in sealants and

mastics is essential to ensure the integrity of the underlying metal surface. Personnel on

offshore facilities should be educated to contribute in performing frequent visual

inspections of the external condition of weatherproofing systems. Sometimes it is a case

of a careless attitude by some employees of not doing the necessary inspections that can

lead to not recognizing the early signs that corrosion under insulation might be starting

beneath the insulation system. The combination of general visual examinations with the

application of risk based inspection programs provides an effective approach for

prioritizing susceptible areas that are more likely to corrosion failures beneath insulation

systems while establishing an appropriate inspection method.

A variety of nondestructive evaluation methods that do not require the removal of

insulation have been improved and used during the recent years to inspect for corrosion

under insulation. Pulsed eddy current is one of the improved tools that measures

remaining wall thickness of equipment. It is an excellent option to assess for average loss

caused by general corrosion but not for cracks that are mostly found on stainless steel

systems. The difficulty with stainless steel systems is that they are subjected to more

stress corrosion cracking attack than general corrosion. Uniform corrosion on metallic

equipment typically produces considerably metal loss suitable to be detected by pulsed

eddy current technology and by the other available nondestructive testing systems.

Consequently, cracks that may be present on stainless steel equipment at an early stage,

have high probabilities to be missed during an inspection program using the existing

nondestructive evaluation techniques since they generate small percentage of weight loss

of the metal and are hardly detected even with the naked eye. If the conditions under the

insulation get more corrosive before the next planned inspection, cracks may penetrate

127

deeply into the metal surface at an accelerated rate causing unwanted and unexpected

corrosion failure that in the best scenario, it may represents a loss of production and not

the loss of human life and damage to the environment.

Another non invasive evaluation technique is neutron backscattering that could be

used as a screening tool to quickly detect areas with wet insulation which will require

further investigation, but interpretation of the data is a challenge because they can be

confused by the fluid within the pipe. The relative new nondestructive evaluation

techniques of long range ultrasonic and magnetostrictive technology seem to be emerging

tools and good options for inspecting large areas of piping during a short period of time.

However, each technique has its limitations. Some common disadvantages of both

techniques are that they are only effective on straight runs of pipes and are not sensitive

enough to detect small cracks on stainless steel equipment. They also require removal of

small areas of insulation to place the associated transducers. These areas may contribute

to potential water sources if they are not properly reinsulated and sealed. The presence of

more thermal spray aluminum as a coating system has been demonstrated to be a

difficulty for many nondestructive evaluations since most of them are suitable for

ferromagnetic materials or they require the removal of the aluminum coating to assess the

condition of the equipment. Therefore, improved and cost effective inspection tools are

needed, particularly to detect small cracks on stainless steel, to overcome the limitations

associated to equipment coated with thermal spray aluminum and for pipe systems with

large number of obstacles, welds and bends that affect the performance of the

inspections.

The latest trend for the oil and gas offshore industry is to use more duplex

stainless steel, super austenitic and martensitic stainless steels on their facilities. This will

play an important role in the corrosion mitigation approaches. Their improved corrosion

resistant properties may be an excellent answer to the persistent problem of corrosion

under insulation. The fact that new and improved corrosion resistant alloys are selected

128

for offshore facilities brings the idea that corrosion failures will be decreased. However,

experience in Norway has shown that a variety of failures have occurred under different

service conditions on piping and equipment manufactured from the new generation of

stainless steel alloys. Therefore, more studies about the performance of these new

materials under insulation systems should be considered in order to review their benefits.

During the last 50 years and after many research projects and studies, it is broadly

accepted that carbon steel is at the greatest risk from corrosion under insulation in service

temperatures in the range of – 4°C to 150°C, while for 300 series stainless steel the

temperature range is from 50°C to 150°C. Corrosion rates under wet insulation and under

cold/wet – hot/dry cycles can be up to 20 times greater than on equipment exposed

directly to atmospheric conditions. Even using improved corrosion resistant materials to

reduce corrosion failures, new corrosion tests, such as those developed for carbon steel

and austenitic stainless steel to understand and establish the conditions under which

corrosion failures are more likely to occur, are needed in order to set up a widely

accepted agreement on the service temperatures at which these new generation of

stainless steel alloys are at higher risk from corrosion under insulation.

Different coatings and insulation systems should be tested on the new stainless

steel alloys under severe corrosive solutions, such as water with high concentrations of

chlorides and with low pH values, in order to help establish what combination of coating

and insulation material promotes less corrosion problems.

In that way, engineers and managers will be able to assess which equipment is at

higher risk for corrosion beneath insulation depending upon the combination of coating

and insulation systems that was applied. Consequently, effective risk based inspection

programs can be applied in the new generation of stainless steel during the life cycle of

the offshore structure.

129

In addition to the establishment of the temperature limits at which the improved

corrosion resistant alloys are more susceptible to deteriorating under insulation systems,

the life of sealants and caulking compounds used to seal the protrusion through weather

barriers play an important role in the risk based management approaches. In the long

term, usually between 3 to 5 years caulking and sealants break down or are subjected to

mechanical abuse to the point that water and moisture can easily bypass the insulation

and reach the metal surface. So the age of insulated equipment or the age of the last

insulation that was installed on the equipment is an important factor when assessing the

probability of failures in offshore facilities. Commonly after 5 years of service, corrosion

under insulation problems are usually found to be significant. Consequently, inspection

and promptly repairs of unsealed protrusions are essential to guarantee the integrity of the

insulation and the underlying equipment.

Furthermore, this new generation of stainless steel equipment must be coated

before the installation of insulation and the type of coatings used must be the best

available option. The benefit of the risk based management approach is that they are

flexible allowing them to be changed and improved when the new data that resulted from

the last inspection become available. Systems that were initially prioritized to be

inspected at a fixed frequency may be evaluated more frequently if corrosion damage is

found after the first evaluation.

The prioritization of corrosion risks depends upon many factors. The range of

temperatures for every type of alloys used on offshore facilities at which they are more

susceptible to corrosion under insulation failures is one of the most important factors that

should be considered during the risk assessments. The development of an awareness

attitude in every offshore employee in order to identify the early signs on insulated

systems that may contribute to potential corrosion failures plays an important role in the

reduction of the risk for corrosion before the application of the next inspection program.

130

Warm temperatures and moisture are the two main triggering factors for corrosion

to occur beneath insulation systems. It is obvious that service temperatures can not be

avoided since they are a necessary part of the offshore oil and gas processing and

production systems. Moisture and water are virtually impossible to be kept out of

insulation systems during the 20 or 40 years of designed life of an offshore structure.

Given that these main factors will continue to be found on offshore facilities, different

approaches can be considered to reduce the occurrence of corrosion under insulation.

Firstly, offshore facilities are and have been affected by corrosion under

insulation because they are subjected to offshore conditions. The use of less topside

systems and more subsea equipment may be an option for the mitigation of corrosion

problems during the next 50 years. The submerge zone of an offshore structure has lower

corrosion rates than the splash and atmospheric region due to the lower quantity of

dissolved oxygen in the sea water. Forty years ago the oil and gas industry had not even

considered building and installing subsea equipment, but thanks to the latest development

in technology more subsea production systems are being successfully selected and used

for the exploitation of new offshore fields. Therefore the idea of using more subsea

systems and less topside facilities may be a possible option to be considered if conditions

and factors, other than the risk of corrosion, represent the most suitable option for a

particular new oil and gas offshore development.

Secondly, if topside production and processing facilities continue to be utilized as

the best option for offshore structures, consideration might be given to building semi

closed offshore structures or semi closed areas that are more susceptible to corrosion in

order to reduce the direct exposure of insulated systems to the corrosive marine

environment. Consequently, less salt spray and rain water will be able to reach jacketing

systems and diffuse into the insulation. This option could be a potential solution to the

problem of corrosion under insulation combined with the application of non absorptive

insulation materials such as aerogels or cellular glass.

131

Moreover, topside facilities could be protected against corrosion under insulation

if the integrity of weather barriers, jacketing systems and caulking compounds are

maintained in optimum conditions throughout the life cycle of the production and

processing facilities. They represent and are designed to be the first line of defense

against water intrusion and mechanical abuse. Insulation materials and topside facilities

rely on the good condition of these systems. The development and application of

effective mechanical integrity programs on these components will play an important role

in the mitigation of corrosion problems under insulation systems. Sometimes, the root of

the problem is the lack of management or communication between offshore personnel

and managers who are responsible and have the capability to make the important decision

to ensure that the offshore assets are maintained in good conditions. An offshore structure

can be built from the best corrosion resistant alloys and the best insulation systems

available in the market, but if there is lack of communication between the parties,

inefficient decisions and late maintenance program put in practice, the problem of

corrosion under insulation will continue to persist as long as oil and gas will exist.

The other corrosion preventative approach that should be considered is the

insulation material. It can be seen as the second line of defense of the whole system. As

was mentioned, insulation materials having a closed cell structure should be selected as

the best option to prevent water intrusion into the insulation. Today, new insulation

materials are manufactured together with new corrosion inhibitor compounds that, if

water finds its way into the insulation, a protective film will be formed on the metal

surface to act as a barrier against corrosion processes. Therefore different insulation

materials should be tested under severe corrosive conditions, particularly on the new

generation of stainless steel alloys in order to evaluate which insulation and corrosion

inhibitor provides the option to mitigate corrosion under wet insulation.

132

Coatings systems have been used as a corrosion protection alternative prior the

installation of insulation systems. Experience has shown that inorganic zinc coatings have

given poor corrosion protection under wet insulation. Additionally, some insulating

materials such as calcium silicate when wet are alkaline, the result being detrimental to

some coating systems. During the last few years thermal spray aluminum coating has

provided successful results in marine conditions. Consequently, this type of coating as

well as the other types available in the market should be evaluated with the different

classes of insulation materials in order to establish the best line of defense against

corrosion under insulation if water and moisture diffuse into the insulation.

Finally, if the proper combination of insulation and coating system is selected

and is effectively installed and maintained, another line of defense against the occurrence

of corrosion under insulation is the type of alloy used for offshore facilities. As was

previously mentioned, the latest tendency in the offshore industry is to use more of the

new generation of stainless steel alloys than originally used austenitic stainless steel and

carbon steel. But, as it was pointed out, new doubts and uncertainties must be answered

about this new generation of improved corrosion resistant materials with the development

of corrosion test and studies, because equipment made of this type of stainless steel alloys

continue to present corrosion failures under conditions that were initially thought to be

less susceptible to corrosion problems.

Summing up, corrosion under insulation is known to be affected by multiple

factors, each one having different levels of corrosion impact on the associated system.

They can produce different corrosive conditions and thereby unexpected failures will

continue to occur. Some of the factors are less controllable than others such as the natural

environment to which insulation systems are exposed, but assessing and understanding

the different lines of defense that can be applied as corrosion mitigation approaches

together with a knowledge of accepted service conditions at which every type of offshore

equipment is at higher risk from corrosion under insulation will reduce corrosion failures.

133

As a result the best suitable nondestructive evaluations will be able to be used at

established periods of time in order to maintain in optimum condition the offshore assets

while safeguarding the human life and the marine environment.

134

8. CONCLUSIONS

After a comprehensive review of the problem of corrosion under insulation on

offshore facilities, the following conclusions can be reached:

1. Corrosion under insulation can occur under all types of insulating materials if

water and moisture enter the insulation and reach the underlying metal surface.

Absorption properties of the insulation play an important role in reducing

corrosion failures of insulated equipment.

2. Equipment design has an influence on the occurrence of corrosion beneath

insulation systems. Shapes that are difficult to insulate are susceptible places

where water can bypass the insulation hardware and thereby corrosion processes

can be initiated.

3. Poorly designed or installed insulation allows water to diffuse into the insulation

and thereby promotes the occurrence of corrosion.

4. Protrusions through weather barriers and jacketing systems represent important

areas to monitor, since caulking compounds and mastics used to seal protrusions

are one of the components of insulation systems that are frequently exposed to

sunlight, chemicals and other external factors that affect their integrity and

performance and with time they are a common source of water intrusion if they

are not periodically inspected and maintained.

5. Insulation materials and associated accessories that contain water leachable

chlorides and acidic compounds have a detrimental effect on the problem of

corrosion under insulation, because they increase the corrosiveness of the water

that diffuses into the insulation.

135

6. Concentration of chlorides in insulation materials, in rain water or in sea water

need not be high to cause corrosion under insulation, since the evaporation action

of a hot metal surface concentrates the chlorides on the underlying surface.

7. The external environment can be considered as the root cause of corrosion under

insulation and the least controllable. The low pH levels of the rain water and

costal fog in the east coast of Canada promote the occurrence of corrosion under

insulation on offshore facilities due to the aggressive corrosion conditions that are

generated when pH of water is less than 6.0.

8. The service temperature has a direct effect on corrosion beneath insulation

systems. As the temperature increases, the rate of corrosion increases. Carbon

steel is at the greatest risk from corrosion under insulation in service temperatures

in the rage of – 4°C to 150°C, while austenitic stainless steel equipment operating

in the temperature range of 50°C to 150°C is at higher risk.

9. General corrosion and pitting corrosion are commonly found on carbon steel

equipment. Austenitic stainless steel alloys are more likely to fail due to stress

corrosion cracking and pitting corrosion under insulation systems.

10. An approach to mitigate the problem of corrosion under insulation is the use of

high quality protective coatings on the underlying metal surface. Experience has

demonstrated good performance of thermal spray aluminum coating and

aluminum foil wrapping in marine environments. However, the long term

performance of any coating system relies on good surface preparation and proper

application procedures.

136

11. If the right insulation material is selected and properly installed, corrosion under

insulation can occur if the integrity of jacketing system is not maintained during

the life cycle of the offshore facilities. Mechanical abuse as a result of the

climbing and walking action of personnel over weather barriers has an important

effect on corrosion under insulation.

12. The use of different types of nondestructive evaluations for each specific system

combined with the application of effective risk based inspection programs

represent the optimum method to mitigate the problem of corrosion under

insulation on existing offshore facilities, since it is generally impossible to inspect

everything. However, removal of insulation seems to be the most reliable

technique to asses the condition of insulated equipment, but the most expensive

and time consuming.

13. The relatively new nondestructive evaluation techniques of long range ultrasonic

and magnetostrictive technology are good options for inspecting large areas of

piping during a short period of time. However, each technique has its limitations,

particularly when they are applied on pipe runs with multiple shapes and

attachments.

137

9. RECOMMENDATIONS

1. Corrosion under insulation can be reduced by cautious selection of insulation

materials. Closed cell and chloride free insulation materials, such as cellular glass

or aerogels, should be selected from the initial design phase of offshore facilities

since they absorb the least amount of water and exhibit a chemical neutral

behavior.

2. Periodic visual inspections to assess the external condition of weather barriers and

seals combined with promptly repairs are two of the principal actions that every

industry should put in practice in order to reduce damaged and unattended areas

where water can easily bypass the insulation and reach the metal surface.

3. Since duplex stainless steel and super austenitic stainless steel are being used

more commonly during the last few years on offshore facilities, there is the need

to establish a common agreement of the operating temperature rage at which these

new generation of alloys are at the greatest risk from corrosion under insulation.

4. There is a need to develop better and cost effective nondestructive evaluation

techniques for detecting stress corrosion cracking on stainless steel equipment. It

is also necessary to improve the applicability of long range ultrasonic testing and

magnetostrictive technology on pipe runs with multiple bends and geometries.

5. A study of the performance of thermal spray aluminum coatings and paint

coatings to protect duplex stainless steel and super austenitic stainless steel should

be conducted under severe conditions such as wet and dry cycles, low pH levels

and high concentration of chlorides using different types of insulation materials to

establish the best practice and compatibility between coatings and insulation

materials to prevent corrosion failures.

138

6. The performance of new mouldable non-metallic jacketing systems should be

evaluated to establish whether they provide better weatherproof and mechanical

properties than the conventional metal jackets.

7. There is a need to develop and study the long term performance and efficacy of

new or improved corrosion inhibitors used in insulation materials that could

withstand wet and dry cycles while providing a protective film on the underlying

metal surface in the case of water and moisture intrusion.

8. Special consideration should be given to systems where operating conditions have

changed in order to assess the risk of corrosion under insulation under the new

service conditions.

9. Insulation systems used on offshore facilities for personnel protection should be

considered to be replaced with metal mesh guards in order to minimize corrosion

problems.

10. An attitude of responsiveness about the problem of corrosion beneath insulation

systems should be created in every employee working on offshore facilities in

order to detect the early signs where potential corrosion failures may occur and

most important to reduce catastrophic failures where human life and the

environment can be endangered.

11. There is the need to design removable and reusable inspection ports suitable for

long range ultrasonic testing system and for the other types of inspection tools

that require the removal of a large area of insulation to place the sensors.

139

12. The use of more subsea production equipment for some oil and gas offshore

developments should be taken into consideration as a corrosion mitigation action,

if the circumstances and factors, other than the risk of corrosion, represent a

suitable option.

13. The possibility of building semi closed offshore facilities or semi closed areas,

which are more susceptible to corrosion, should be also considered in order to

reduce the direct exposure of insulated systems to the corrosive marine

environment.

140

10. REFERENCES [1] Shreir, L.L., Jarman, R.A. and Burstein, G.T., Corrosion, Third Edition, Volume

2, Elsevier, Oxford, United Kingdom, 1994. [2] Smith, M.R., The World Offshore Oil and Gas Forecast 2007-2011 [online]. Available: http://www.dw-1.com [2007, 14 May]. [3] Lettich, M., “Is There a Cure for Corrosion under Insulation”, Insulation Outlook

Magazine, Nov. 2005. [4] Byars, H.G., Corrosion Control in Petroleum Production, Second Edition,

National Association of Corrosion Engineers International, Houston, Texas, 1999. [5] Hilchie, M.J., Protective Coatings for Preventing Corrosion of Structural Steel in

the Marine Environment, master thesis, Dalhousie University, Halifax, Canada, 1990.

[6] Fontana, M.G., Corrosion Engineering, Third Edition, McGraw-Hill, Singapore,

1986. [7] Corrosion Cell [online].

Available: http://octane.nmt.edu/waterquality/corrosion/corrosion.htm [2007, 21 May].

[8] Bradford, S., Corrosion Control, Second Edition, Casti Publishing Inc., Alberta,

Canada, 2003. [9] Munger, C.G., Corrosion Prevention by Coatings, National Association of

Corrosion Engineers, Houston, USA, 1984. [10] Garverick, L., Corrosion in the Petrochemical Industry, American Society for

Testing and Materials International, USA, 1994. [11] The Hidden Threat to All Chill and Cold Water Piping [online]. Available: http://www.corrview.com/tech_p_06.htm [2007, 23 May]. [12] Landrum, R.J., Fundamentals of Designing for Corrosion, National Association of

Corrosion Engineers, Houston, Texas, 1989. [13] Corrosion Investigation [online]. Available: http://www.met-tech.com/corrosion.htm [2007, 23 May].

141

[14] Corrosion forms [online]. Available: http://www.corrosion-doctors.org/Forms/FormType.htm [2007, 23 May].

[15] Hydrogen Embrittlement [online].

Available:http://www.corrosion-doctors.org/Forms-HIC/embrittlement.htm [2007, 20 May].

[16] Intergranular Corrosion [online]. Available: http://www.ksc.nasa.gov/images/fireplug [2007, 25 May]. [17] Banrhart, J.M., “The Function of Thermal Insulation,” Corrosion of Metals Under

Thermal Insulation, ASTM STP 880, American Society for Testing and Materials, pp 5-8, Philadelphia, USA, 1985.

[18] Watson, D., “National Insulation Standards”, Thermal Insulation Association of Canada, Canada, 2005. [19] Mont, J., Harrison, M., Energy Management Handbook, The Fairmount Press,

Denver, Colorado, 2001. [20] Frankel, M., Facility Piping System Handbook, Second Edition, McGraw-Hill,

New York, USA, 2002. [21] Moon, T. “Innovative Insulation Proves Viable for Offshore Production,”

Offshore Magazine, vol. 66, no. 1, pp 78, Jan. 2006. [22] Chacko, J., Ghalambor, A., Guo, B. and Song, S., Offshore Pipelines, Elsevier,

Oxford, United Kingdom, 2005. [23] Energy, Mines and Resources Canada, “Process Insulation,” Energy Management

Series for Industry Commerce and Institutions, Department of Energy, Mines and Resources, Ontario, Canada, 1987.

[24] Kalis, J.W., “Optimum Insulation Systems for Cold Service,” Insulation Outlook

Magazine, Jan. 2005. [25] Lang, G.E., “Thermal Insulation Materials: Generic Types and Their Properties,”

Corrosion of Metals Under Thermal Insulation, ASTM STP 880, American Society for Testing and Materials, pp 63-68, Philadelphia, USA, 1985.

[26] Hills, O., “How Dry Is Your Insulation”, IOM Corrosion under Insulation

Conference, Sheffield, United Kingdom, 2004.

142

[27] National Association of Corrosion Engineers, “The Control of Corrosion Under Thermal Insulation and Fireproofing Materials – A System Approach,” NACE Standard RP0198-2004, NACE International, Houston, USA, 2004.

[28] Pigging, A. and Meara, K., “The Versatile Insulation,” Insulation Outlook,

National Insulation Association, August 2002, Virginia, USA, 2002. [29] The Welding Institute, “Thermally Sprayed Aluminum for Mitigation of

Corrosion under Insulation – Phase 1 Carbon Steels”, TWI Ltd, Cambridge, United Kingdom, 2006.

[30] Ranniey, W.M., Offshore Oil Technology, Recent Developments, Noyes Data

Corporation, New Jersey, USA, 1997. [31] Canadian Association of Petroleum Producers, “Production Oil and Gas Offshore

in Atlantic Canada”, Prisma Productions, Halifax, Canada, 2005. [32] Levy, D., An Introduction to Offshore Maintenance, First Edition, Oilfield

Publication Limited, Herefordshire, United Kingdom, 1991. [33] Mather, A., Offshore Engineering, An Introduction, Whiterby and Company

Limited, London, United Kingdom, 1995. [34] Wimik, S., “Corrosion Under Insulation, a Historical Perspective”, IOM

Corrosion under Insulation Conference, Sheffield, United Kingdom, 2004. [35] Chandler, K.A., Marine and Offshore Corrosion, Butterworths, London, United

Kingdom, 1985. [36] “Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment”,

NACE Standard MR 0175-98, National Association of Corrosion Engineers, Houston, Texas, 2004.

[37] Taylor, D.O. and Bennett, R. D., “Shell and Jacket Corrosion of a Foamed in

Place Thermally Insulated Liquefied Petroleum Gas Tank”, Corrosion of Metals Under Thermal Insulation, ASTM STP 880, American Society for Testing and Materials, pp 114-120, Philadelphia, USA, 1985.

[38] Lazar, P., “Factors affecting Corrosion of Carbon Steel under Thermal

Insulation”, Corrosion of Metals Under Thermal Insulation, eds. Barnhart, J. M., Pollock, W. I., ASTM STP 880, American Society for Testing and Materials, pp 11-26, Philadelphia, USA, 1985.

143

[39] Sandberg, T. “Experience with Corrosion Beneath Thermal Insulation in a Petrochemical Plant”, Corrosion of Metals Under Thermal Insulation, eds. Barnhart, J. M., Pollock, W. I., ASTM STP 880, American Society for Testing and Materials, pp 71-85, Philadelphia, USA, 1985.

[40] Leonard, A., “Review of External Stress Corrosion Cracking of 22% Cr Duplex

Stainless Steel, Health and Safety Executive Book, Alberdine, United Kingdom, 2003.

[41] American Petroleum Institute, “Damage Mechanisms Affecting Fixed Equipment

in the Refining Industry”, API Recommended Practice 571, First Edition, American Petroleum Institute, Washington, USA, 2003.

[42] McIntyre, P., “Corrosion Management for Upstream Oil and Gas”, Corrosion

Engineering, Journal of Science and Technology, vol. 38, no. 2, April 2003. [43] Whitaker, T., “Avoid Pipe Corrosion Under Insulation”, Hydrocarbon Processing,

vol. 75, April 2005. [44] Funderburg, I. M., “An Industry Perspective: Revisiting Recommendations”,

Insulation Outlook, Nov. 2006. [45] Ahluwalia, H. S., “CUI: An In Depth Analysis”, Insulation Outlook Magazine,

Nov. 2006. [46] Dunn, P. J. and Norsworthy, R., “Control of Corrosion under Insulation”,

ASHRAE Journal, March 2003. [47] Schumacher, M., Seawater Corrosion Handbook, Noyes Data Corporation, New

Jersey, USA, 1979. [48] Revie, R., Uhlig's Corrosion Handbook, Second Edition, John Wiley and Sons,

Toronto, Canada, 2000. [49] Schweitzer, P. A., Fundamentals of Metallic Corrosion: Atmospheric and Media

Corrosion of Metals, Taylor and Francis Group, Boca Raton, USA, 2006. [50] Canada – United Sates Air Quality [online].

Available: http://www.ec.gc.ca/cleanairairpur/caol/canus/report/ 2006canus/cl_p2_e.cfm#52_6 [2007, 17 July].

[51] Posteraro, K., “Thwart Corrosion under Insulation” Chemical Engineering

Progress, vol. 95, pp 43, Oct. 1999.

144

[52] The Committee on the Environment and the Northeast International on Energy of the Conference of New England Governors and Eastern Canadian Premiers, “Climate Change action Plan 2001”, Eastern Canadian Secretariat, Halifax, Canada, 1998.

[53] Hill, O., “How Dry is your Insulation”, IOM Corrosion under Insulation

Conference, Sheffield, United Kingdom, 2004. [54] Acid Rain and Water [online].

Available: http://www.ec.gc/acidrain/acidwater.html [2007, 17 July]. [55] Beauchamp, S., Pinette, A., Tordon, R., “Chemistry and Deposition of Acidifying

Substances by Marine Advection Fog in Atlantic Canada”, Atmospheric Division Environment Canada, Dartmouth, Canada, 1998.

[56] Atlantic Climate Centre [online].

Available: http://www.atlantic-web1.ns.ec.gc.ca/climatecentre [2007, 18 July]. [57] Speller, F. N., Corrosion – Causes and Prevention, Second Edition, McGraw-Hill

Book Company, New York, USA, 1935. [58] Ashbaugh, W. G., “Corrosion of Steel and Stainless Under Thermal Insulation”,

In Process industry Corrosion, eds. Moniz, B. J., Pollock W. I., National Association of Corrosion Engineers, pp 761, Houston, USA, 1986.

[59] Hill, O., “Corrosion – The Hidden Danger”, World Pipelines, Oct. 2005. [60] Goldberg, L., “Take a System Approach to Corrosion Under Insulation”,

Chemical Engineering Progress, vol. 96, pp 63, March 2000. [61] American Petroleum Institute, “Piping Inspection Code: Inspection, Repair,

Alteration, and Rerating of In-Service Piping Systems”, API 570, American Petroleum Institute, Washington, USA, 2003.

[62] Twomey, M. “Detecting Corrosion Under Insulation”, Hydrocarbon Processing,

vol. 76, pp 76, Jan. 1997. [63] Miller, J. M., “Development in NDT Techniques for Use in the Offshore

Industry”, Institution of Electrical Engineers, London, United Kingdom, 1999. [64] McFarland, S., “Practical Experience of Corrosion Under Insulation –Detection

and Mitigation”, IOM Corrosion Under Insulation Conference, Sheffield, United Kingdom, 2004.

145

[65] Kwun, H. and Light, G. M., “Magnetostrictive Sensor Technology Proven in Process Application” Oil and Gas Journal, May 22, 2000.

[66] American Petroleum Institute, “Risk Based Inspections”, API Recommended

Practice 580, First Edition, American Petroleum Institute, Washington, USA, 2002.

[67] Shreir, L., Corrosion, vol. 2, Newnes-Butterworth Ltd., London, United Kingdom,

1977. [68] Tator, K.B., “How Coatings Protect and Why They Fail”, Paper # 4,

Corrosion’77, National Association of Corrosion Engineers, pp 1-18, March 1977.

[69] Davis, J.R., Surface Engineering for Corrosion and Wear Resistance, Woodhead

Publishing, Ohio, USA, 2001. [70] Christman, J., “Thermal Sprayed Aluminum Corrosion Protection System for the

Petrochemical Industry”, Sermatech International, May 2006. [71] Morrison, K., ExxonMobil, Halifax, Nova Scotia, Personal Communication, 23

July 2007. [72] Schremp, F.W., “Corrosion Prevention for Offshore Platforms”, Journal of

Petroleum Technology, pp 605 -611, Apr. 1984. [73] Ashbaugh, W.G. and Laundrie, T.F., “A Study of Corrosion of Steel Under a

Variety of Thermal Insulation Materials”, Corrosion of Metals Under Thermal Insulation, eds. Barnhart, J. M., Pollock, W. I., ASTM STP 880, American Society for Testing and Materials, pp 121-131, Philadelphia, USA, 1985.

[74] Richardson, J.A. and Fitzsimmons, T., “Use of Aluminum Foil for Prevention of

Stress Corrosion Cracking of Austenitic Stainless Steel Under Thermal Insulation”, Corrosion of Metals Under Thermal Insulation, eds. Barnhart, J. M., Pollock, W. I., ASTM STP 880, American Society for Testing and Materials, pp 188-198, Philadelphia, USA, 1985.

[75] Leonard, A., “Review of external stress corrosion cracking of 22%Cr duplex

stainless steel Phase 1 – Operational data acquisition”, Research Report 129, Health and Safety Executive, Cambridge, United Kingdom, 2003.

146

APPENDICES

147

APPENDIX A BASIC TYPES OF INSULATION FOR LOW TEMPERATURES [23]

148

APPENDIX B

BASIC TYPES OF INSULATION FOR INTERMEDIATE TEMPERATURES [23]

149

APPENDIX C BASIC TYPES OF INSULATION FOR HIGH TEMPERATURES [23]

150

APENDIX D

PROTECTIVE COVERINGS AND FINISHES [23]

151

APENDIX E TYPICAL OIL AND ASSOCIATED GAS PRODUCTION PROCESS [33]

152

APENDIX F TYPICAL GAS PRODUCTION PROCESS [33]