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 authors 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

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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

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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

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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

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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 108C 119

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

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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

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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 xC = Watts per metre degree Celsius

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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 -4C to 150C 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].

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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-; SO42-; 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 -75C to 815C. Insulation materials

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

and those above 815C 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 35C to 815C 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

150C 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

315C, 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 1.5C to 422C. 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 -73C to

149C for Polyisocyanurate foams and from -73C to 82C 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 105C 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].

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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.

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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].

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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].

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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]

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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].

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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

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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].

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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