MSc Subsea Engineering Final Thesis

CRANFIELD UNIVERSITY
OKEREKE, CHUKWUNONSO N.
AGEING OF OFFSHORE ASSETS: ISSUES AND CHALLENGES
SCHOOL OF ENERGY, ENVIRONMENTAL TECHNOLOGY AND
AGRIFOOD
Offshore and Ocean Technology with Subsea Engineering
MSc.
Academic Year: 2014 - 2015
Supervisor: Dr. Weizhong Fei
September 2015

CRANFIELD UNIVERSITY
SCHOOL OF ENERGY, ENVIRONMENTAL TECHNOLOGY AND
AGRIFOOD
Offshore and Ocean Technology with Subsea Engineering
MSc
Academic Year 2014 - 2015
OKEREKE, CHUKWUNONSO N.
Ageing of Offshore Assets: Issues and Challenges
Supervisor: Dr. Weizhong Fei
September 2015
This thesis is submitted in partial fulfilment of the requirements for
the degree of MSc. Offshore and Ocean Technology with Subsea
Engineering
© Cranfield University 2015. All rights reserved. No part of this
publication may be reproduced without the written permission of the
copyright owner.

i
ABSTRACT
Offshore asset infrastructures (subsea pipelines, platforms, risers, jacket
structures) are usually subjected to deterioration to a large extent. This growing
degradation is recognized as "ageing" process. This ageing situation has
become significantly important for the offshore oil and gas and the renewable
energy industries because many assets within these sectors are beyond their
original life expectancy. It is needed for these assets, some of which have
passed their design life, to continue being utilized but with minimal human,
environmental and economic risks. With the unstable changes in oil price and
ageing nature of current offshore installations, the capability for operators to
employ assets outside the limits of the original design life, for either short,
medium or long term while still making sure that high levels of Health, Safety
and Environment and Integrity Management is of very great importance and is
an important part of any plan to take control of present and subsequent
business risk. This paper attends to the issues and challenges applicable to
ageing, managing of ageing and extending the life of ageing offshore
installations.
Keywords:
Life extension, degradation, structural integrity, safety critical elements,
Hurricane Ivan.

iii
ACKNOWLEDGEMENTS
This research paper is made possible by God through the help and support of
everyone including my parents Prof. and Mrs. C.S. Okereke. Especially, I would
like to dedicate my acknowledgement of gratitude to the following significant
advisors and contributors.
First and foremost, I would like to thank my supervisor Dr. Weizhong Fei for his
support and encouragement. He gave me utmost guidance through the duration
of my research always offering detailed advice on grammar, organization and
theme of the paper.
Second, I would like to thank Dr. Mahmood Shafiee who also provided valuable
advices on how to go about my research, as well as all other lecturers who
taught me over the last one year. I am grateful to even the non-teaching staff
who helped along the way, especially Jessica Puttick and the rest in the SEEA
office.
Finally, I sincerely thank my colleagues and friends who helped throughout my
course of study most especially Patrick Chukwulami Osere and Alexander Obi.
The product of this research paper would not be possible without them.

v
TABLE OF CONTENTS
ABSTRACT ......................................................................................................... i
ACKNOWLEDGEMENTS...................................................................................iii
LIST OF FIGURES............................................................................................vii
LIST OF TABLES...............................................................................................ix
LIST OF EQUATIONS........................................................................................ x
LIST OF ABBREVIATIONS................................................................................xi
1 INTRODUCTION............................................................................................. 1
1.1 Ageing Scenarios...................................................................................... 3
1.2 Aims and Objectives ................................................................................. 3
1.3 Methodology ............................................................................................. 4
2 REVIEW OF AGEING ..................................................................................... 5
2.1 Analysis of Ageing Process ...................................................................... 5
2.2 Ageing Effects........................................................................................... 8
2.2.1 Degradation........................................................................................ 9
2.2.2 Corrosion............................................................................................ 9
2.2.3 Fatigue ............................................................................................. 12
2.2.4 Obsolescence .................................................................................. 15
2.2.5 Organisational Issues....................................................................... 15
3 REVIEW OF AGEING MANAGEMENT......................................................... 17
3.1 Asset Life Extension ............................................................................... 17
3.2 Safety Critical Elements.......................................................................... 21
3.2.1 Performance Standards ................................................................... 21
3.2.2 Development of Ageing SCEs Management Structure..................... 21
3.3 Maintenance of Physical Asset ............................................................... 23
3.3.1 Modern Maintenance Techniques .................................................... 23
4 STRUCTURAL INTEGRITY MANAGEMENT (SIM)...................................... 25
4.1 Overview................................................................................................. 25
4.2 Elements of SIM...................................................................................... 25
4.2.1 Data Management............................................................................ 26
4.2.2 Evaluation (Assessment).................................................................. 26
4.3 Strategy .................................................................................................. 30
4.4 Program.................................................................................................. 31
5 RISK BASED INSPECTION.......................................................................... 33
5.1 Overview................................................................................................. 33
5.2 RBI Model............................................................................................... 35
6 CASE STUDY ............................................................................................... 37
6.1 Case Study on Hurricane Ivan’s Damage on Offshore Structures in
the GOM ....................................................................................................... 37
6.2 Results.................................................................................................... 37
6.2.1 Qualitative Assessment.................................................................... 37

vi
6.2.2 Quantitative Assessment.................................................................. 40
6.2.3 Recommendations from Case Study................................................ 41
7 DISCUSSION................................................................................................ 43
7.1 General discussion ................................................................................. 43
7.2 Problems Associated with Ageing........................................................... 44
7.3 Limitations to Ageing Management and Asset Life Extension
(Challenges) ................................................................................................. 44
8 CONCLUSION .............................................................................................. 47
REFERENCES................................................................................................. 49
APPENDICES .................................................................................................. 53
Appendix A Probability of Failure Assessment ............................................. 53
Appendix B Important Ageing and Life Extension Codes and Standards ..... 60

vii
LIST OF FIGURES
Figure 1-1: Age Histogram for UKCS Platforms (Stacey, Sharp, & Birkinshaw,
2008) ........................................................................................................... 1
Figure 1-2: Ageing scenarios.............................................................................. 3
Figure 2-1: Stages of an equipment life. (Wright, 2011) ..................................... 6
Figure 2-2: Ageing management (Hokstad, Habrekke, Johnsen, & Sangesland,
2010) ........................................................................................................... 7
Figure 2-3: Connection between ageing management and life extension (Perez
Ramirez, Bouwer, & Haskins, 2013)............................................................ 8
Figure 2-4: Histogram showing causes of equipment failure. (Wright, 2011) ..... 9
Figure 2-5: Riser corrosion in splash zone (Clock Spring Company, 2012) ..... 10
Figure 2-6: Common fatigue failures in steel parts (ESDEP course accessed on
26/08/2015) ............................................................................................... 13
Figure 2-7: Alexander Keilland Platform fatigue failure (Exponent Inc, 2010) .. 15
Figure 3-1: Organizational context development considerations...................... 18
Figure 3-2: Offshore Production Platforms (Moan, 2005)................................. 19
Figure 3-3: Commonplace North Sea type steel jacket platform (STATOIL,
2013) ......................................................................................................... 20
Figure 3-4: Tubular joints and braces illustration (El-Reedy, 2002).................. 20
Figure 3-5: Illustration of procedures for SCEs management........................... 22
Figure 4-1: SIM flowchart (Dinovitzer, Semiga , Tiku, Bonneau, Wang, & Chen,
2009) ......................................................................................................... 25
Figure 4-2: Normal design analysis (left), refined analysis (right) procedures.
(O'Connor, Bucknell, DeFranco, Westlake, & Puskar, 2005)..................... 28
Figure 4-3: Joint selection for inspection (Piva, Latronico , Sartirana, Gabetta , &
Nero, 2013)................................................................................................ 29
Figure 4-4: Fracture mechanics approach (Marshall & Copanoglu, 2009) ....... 30
Figure 5-1: Reliability based maintenance framework based on ISO 3100 ...... 34
Figure 5-2: The RBI process ............................................................................ 36
Figure 6-1: Hurricane Ivan path showing locations of destroyed platforms
(Energo Engineering Inc., 2005)................................................................ 42

viii
Figure A-1: Comparing alternate inspection programs with same range but
different frequencies (Rouhan & Schoefs, 2003)....................................... 58
Figure A-2: Risks related with alternative structural inspection programs for a
platform (Barton & Descamps, 2001) ........................................................ 60

ix
LIST OF TABLES
Table 2-1: Structural components prone to corrosion (Galbraith & Sharp, 2007)
.................................................................................................................. 11
Table 2-2: Structural parts prone to fatigue (Galbraith & Sharp, 2007) ............ 14
Table 5-1: Examples of inspection methods. (Animah, 2012) .......................... 34
Table 6-1: Fixed platforms destroyed by Hurricane Ivan (Energo Engineering
Inc., 2005).................................................................................................. 38
Table A-1: Assessment of PoF due to individual influencing determinant (Barton
& Descamps, 2001) ................................................................................... 53
Table A-2: Inspection ratios for typical inspection methods (Barton & Descamps,
2001) ......................................................................................................... 55
Table A-3: Reliability and cost estimates for CVI and MPI (Marshall & Goldberg,
2009) ......................................................................................................... 56
Table A-4: Example of qualitative consequence rating (Animah, 2012) ........... 57
Table B-1.......................................................................................................... 60

x
LIST OF EQUATIONS
Equation 1 ........................................................................................................ 54
Equation 2 ........................................................................................................ 55
Equation 3 ........................................................................................................ 58
Equation 4 ........................................................................................................ 59

xi
LIST OF ABBREVIATIONS
UKCS
ALARP
ALE
LE
COF
CVI
DL
EDI
FL
FMD
FRA
GVI
HSE
IMR
MAE
MPI
NS
GOM
POD
PS
POF
United Kingdom Continental Shelf
As low as reasonably practicable
Asset life extension
Life extension
Consequence of failure
Close visual inspection
Design life
Eddy current inspection
Fatigue life
Flooded member detection
Fatigue reliability analysis
General visual inspection
Health and safety executive
Inspection, maintenance and repair
Major accident event
Magnetic particle inspection
North sea
Gulf of Mexico
Probability of detection
Performance standards
Probability of failure

xii
RSR
PSA
SCE
SHE
SIM
TT
ULS
UT
CBM
FM
RBI
MMS
DNV
Inc.
ISO
Reserve strength ratio
Petroleum Safety Authority
Safety critical elements
Safety, health and environment
Structural integrity management
Through-thickness
Ultimate limit scale
Ultrasonic testing
Condition based maintenance
Fracture mechanics
Risk based inspection
Minerals Management Service
Det Norske Veritas
Incorporation
International Organization for Standardization

1
1 INTRODUCTION
A whole lot of fixed offshore installations in operation have exceeded their
conventional theoretical 25 years design life. The demand for the continued use
of assets after their design life is exceeded would continue to go higher. There
exists a persistent necessity for them to be utilized in oil and gas production,
therefore they are operated for a symbolic period of time exceeding many years
above the design life. Statistics show that many offshore installations are
beyond their original design life and the trend is increasing with the relative
decrease in platform decommissioning and installations of new offshore
structures. Using the United Kingdom Continental Shelf (UKCS) as a reference,
the diagram in Figure 1-1 shows the age profile for fixed platforms. (Stacey,
Sharp, & Birkinshaw, 2008)
Figure 1-1: Age Histogram for UKCS Platforms (Stacey, Sharp, & Birkinshaw,
2008)

2
Paying attention to the UKCS, several movable offshore installations have been
employed in the UKCS to be utilized as production platforms resulting in
unending or use at the point of interest (on-station). These installations were not
designed for such method of use. This is because activities like routine
inspection, maintenance and repair are not possible in these cases. But as
these structures are being utilized, they continue to deteriorate and this
deterioration is known as ageing. (Stacey, Sharp, & Birkinshaw, 2008)
Ageing is broader than considering only structural integrity. However, it is
characterized by degradation due to fatigue and corrosion and reduces
structural integrity with severe consequences. When the offshore structural
integrity is compromised, failure risk increases with time and this can be
avoided solely by proper management. (Stacey, Sharp, & Birkinshaw, 2008)
Important ageing issues include:
 Ageing/degradation: this includes internal/external corrosion, structural
deterioration like fatigue, uncompleted maintenance work, amassed
results of adjustments.
 Diversity in process circumstances over time.
 Dying out.
Many of these issues can take place as grovelling changes that increase with
time, some occurring with little hints or as an outcome of extensive offshore
structure development.
For structural integrity management to be done properly, an installation’s
weakness and corrosion conditions as well as its response to ageing has to be
known precisely. Correct inspection methods and structural analysis methods
are needed to achieve this. The appropriate balance must be achieved between
the two processes especially for ageing structures with higher possibility of
degradation

3
1.1 Ageing Scenarios
The figure below gives clear knowledge of the different scenarios common to
ageing offshore installations
1.2 Aims and Objectives
This project aims to:
 Review the existing issues and challenges concerned with ageing of
offshore assets.
 Describe through case studies, a well arranged or organized approach to
help with extension of life of ageing offshore assets.
 Develop an analytical model to identify, assess and prioritize the
potential ageing threats to offshore assets.
 Develop a safety barrier model to control (mitigate/minimize) the ageing
damages while ensuring the integrity of assets and keeping the risk of
assets failure as low as reasonably practicable (ALARP).
 Identify asset reliability and integrity issues to be addressed in order to
allow an asset operate beyond its design life.
AGEING
SCENARIOS
TIME-RELIANT
PROCESS DAMAGE
OVER TIME
EXTERNAL
CHANGES
FATIGUE
CORRSION
CREEP
ACCIDENTAL
DAMAGE
ENVIRONMENTAL
BURDEN
GEOLOGICAL
MODIFICATIONS
NEW
TECHNOLOGIES
FAILURE TO
ADAPT TO
CHANGES
Figure 1-2: Ageing scenarios

4
1.3 Methodology
The research methodology established the major determinants that aid ageing
and ways for managing ageing and extending asset life. Theoretical data were
used to establish ageing management and life extension methods. Literature
review from valid journals, conference proceedings, books, reports, websites
were utilized in analysing current oil and gas industry structures, these
literatures are cited accordingly. One case study is discussed and this case
study helps establish issues and challenges associated with ageing offshore
assets and their managements and life extension.

5
2 REVIEW OF AGEING
2.1 Analysis of Ageing Process
A lot of offshore structures are created according to codes and guidelines or
standards depending on limit states including design life. Ageing which we
already know is as a result of exceeding design life would most often disturb the
fatigue limit state of the offshore installation.
According to ISO 1990, the design life is the estimated length of time in which
an installation or component is to be utilized for its purpose with expected
maintenance but without any extraordinary repairs as a result of ageing. Design
life is associated with fatigue life. The UK Department of Energy and the Health
and Safety Executive guidance cites a minimum of 20 years design life for
offshore installations. In some special cases, up to 60 years of design life have
been designated. Design life can be reassessed or requalified.
The most common concept related to ageing is that provided by The UK Health
and Safety Executive (HSE). It states that, ageing is not about how old the
equipment is but about what is known about its condition and how that changes
with respect to time. (Nabavian & Morshed, 2010) In addition, ageing is also
viewed as constant alterations or adjustments that usually have a negative
effect on the structural integrity of offshore installations. There are two contexts
from which ageing can be viewed. (Hokstad, Habrekke, Johnsen, &
Sangesland, 2010) They include:
 Ageing that has to do with reliability. This has to do with failures taking
place in a system (loss of function, failure rates etc.).
 Physically inclined ageing. This has to do with the slow deterioration
process of equipment features.
The figure below shows the life cycle of equipment which might be a structure
or component. Equipment that has reached mature phase is assumed to work
still within the design restrictions aided by regular checks and maintenance with
a rather slow deterioration process. It is also aided by the fact that installation
and commissioning matters, design flaws and early phase life operating errors

6
have been determined during the beginning work stage. The structure reaches
design limit when it gets to the ageing phase and hence would need more
constant repairs as a result of increased deterioration rate. At the end of life
phase, even more extreme inspection techniques and extensive repairs would
be required to inhibit the fast degradation. (Wright, 2011)
Figure 2-1: Stages of an equipment life. (Wright, 2011)
Failure could be regarded as deficit in function of an installation. Failure can
either be non-disastrous.
The effects of ageing are not only connected to equipment, this can be seen on
Figure 2-2 below. The Foundation for Scientific and Industrial Research
(SINTEF) demonstrates ageing management from three extensive
perspectives. These include; material deterioration, obsolescence and
organizational problems or issues. Figure 2-3 below, shows the connection
between ageing management, design life and life extension of offshore assets.
The dotted lines in figure 4 represent the design life of the structure.
Management of ageing through this period helps improve the safety margin of

7
the structure during the life extension phase. A huge safety margin indicates a
longer life extension period.
AGEING MANAGEMENT
Material degradation
Material features
Operational situations
Environmental
circumstances
Maintenance
methods
Obsolescence
Equipment
expired
New
requirements
Advance in
technology
Organizational
problems
Re-organization
Personnel ageing
Knowledge
transmission
Figure 2-2: Ageing management (Hokstad, Habrekke, Johnsen, &
Sangesland, 2010)

8
Figure 2-3: Connection between ageing management and life extension (Perez
Ramirez, Bouwer, & Haskins, 2013)
2.2 Ageing Effects
Ageing has adverse effects on offshore oil and gas installations. Most of these
effects can either lead to a malfunctioning of the installation or a total
breakdown of the installation. Some of the effects of ageing are discussed
below.

9
2.2.1 Degradation
Degradation of material depicts physical aspect of ageing. This aspect of ageing
is not necessarily assessed with respect to time but it helps provide knowledge
of probability of failure as time goes on. (Animah, 2012) The main degradation
methods related to time are fatigue and corrosion. (Piva, Latronico , Sartirana,
Gabetta , & Nero, 2013) Studies have shown that corrosion is responsible for
most failures. This includes general and stress corrosion cracking.
Figure 2-4: Histogram showing causes of equipment failure. (Wright, 2011)
2.2.2 Corrosion
Corrosion comprises an interaction between a material and the environment
such as air, sea, etc. resulting in a decay of the material. Corrosion is time-
related and hence, an important topic to ageing offshore installations.
Corrosion should be managed aggressively as this is important for life
extension, especially in the splash zone where cathodic protection is useless as
a result of steady water level change. Spray paints or epoxy coatings can be
employed to tackle corrosion in such situations. (Marsh & Selfridge) And in

10
some or rather, most cases, sacrificial anode technique is used to protect the
whole structure from corrosion. The figure below shows the deterioration as a
result of corrosion, a predominant ageing process in the splash zone.
Figure 2-5: Riser corrosion in splash zone (Clock Spring Company, 2012)
The table below illustrates components of an offshore illustration that are
susceptible to corrosion, the effects that the corrosion of these parts have , the
risk management methods and factors to be considered in the life extension
process for these components.

11
Table 2-1: Structural components prone to corrosion (Galbraith & Sharp, 2007)
Element Risk
management
measures
Consequence
of failure
Issues of life
extension
Steel sub-
structure
Cathodic
protection
system
design.
Regular
checks, CP
levels
measurement,
anodes
replacement
(if required).
Member or
joint failure as
a result
reduction in
wall
thickness.
State of CP
system and
anodes, CP
levels.
Replacement
of anodes if
required.
Welded
piles
CP system is
partially
effective, they
are difficult to
inspect.
Pile failure
causing tilting
or collapse of
topside, with
risks to
workers.
Difficult
process due to
in-service
inspection
issues.
Steel
structure in
splash
zone
Inclusion of
design
thickness
allowance,
use of
coatings,
regular
inspections.
Component
or joint failure
as a result of
reduction in
wall
thickness.
Results from
recent
inspections,
state of
coatings,
measurements
of wall
thickness if
required (to
evaluate loss
of design
allowance)
Underwater
structural
supports
for risers
Design of
cathodic
protection
system.
Regular
inspections.
Application of
coatings in
certain cases.
Riser
vibration,
fatigue and
local failure
that could
result in gas
or oil spillage.
Results from
recent
inspections.
Topside
structural
supports
Painting,
coating,
regular
inspection
and
maintenance
of coating as
required.
Wall
thickness
loss,
reduction in
member
strength,
possible local
collapse.
Results from
recent
inspections.

12
2.2.3 Fatigue
Fatigue is a great risk to offshore installations in harsh environments such as
the North Sea and Gulf of Mexico. This most times is used as a standard for the
design life. Fatigue is time dependent. Cracks start up and multiply in the
course of the operational life of offshore structures, occurring at welded joints
that are highly stressed and fatigue failure happens as a result of through-
thickness crack formation.
It is recognized that cracking can also take place during the design life of
offshore structures, especially if there is still presence of flaws from the
manufacturing process. In recent times, incidents have occurred due to fatigue
failures in the offshore environment. The repercussion of regional fatigue failure
has to be figured out well in the management of ageing of offshore installations.
(Stacey, Sharp, & Birkinshaw, 2008).
Fatigue can also lead to breakdowns as a result of wave-induced vertical
hydrodynamic loading or environmental conditions such as storms. Figure 2-6
below, shows fatigue failures in steel parts in microscopic views. Observation
from the photos is an area showing crack initiation and propagation. Also in the
photo can be seen, a rougher area which indicates the final area of fracture in
which the crack improves in an unstable manner. High loading at point of
fracture is depicted by a large fracture area.

13
Figure 2-6: Common fatigue failures in steel parts (ESDEP course accessed on
26/08/2015)
Table 2-2 shows some structural elements that are prone to fatigue. Also, it can
be seen on the table, the different ways to manage the risks associated with the
different elements and factors to be considered when carrying out life extension
measures on the ageing components. Figure 2-7 shows the damage done to
the Alexander Keilland platform, a semi-submersible rig that operated in
Norwegian waters. The platform capsized in March 1980 while working in the
Ekofisk oil field. This collapse was due to a fatigue crack in one of the six
braces that acted as a connection between the platform leg and the rest of the
rig. 123 lives were lost.
However, it is noteworthy to know that being able to predict fatigue life is very
important in ageing management and offshore structures life extension.

14
Table 2-2: Structural parts prone to fatigue (Galbraith & Sharp, 2007)
Element Risk
management
practices
Failure
consequences
Issues for
life
extension
Sub-
structure-
welded
joints
Planned
fatigue life
during design
and regular
inspections.
Joint failure,
widespread
fatigue crack
could occur
resulting in
structural
integrity loss.
Range of
design
fatigue
lives, level
of joints’
cracking,
possible
need for
repair.
Welded
piles
Planned
fatigue life
during
design,
lessen
fatigue
damage
during pile
driving,
difficult to
perform in-
service
inspections.
Pile failure could
result in
platform tilt,
pipework
damage and put
workers at risk.
Design
fatigue
lives,
fatigue
damage
from pile
driving,
possible
need for
inspection
Underwater
structural
supports
for risers.
Design
fatigue life,
regular
inspection.
Riser vibration,
fatigue and local
failure,
possibility of oil
or gas release.
Results
from recent
inspections.
Topside
structural
supports.
Design
fatigue life,
regular
inspection.
Failure of plant
support
systems,
cranes, flare
tower,
accommodation.
Results
from recent
inspections.

15
Figure 2-7: Alexander Keilland Platform fatigue failure (Exponent Inc, 2010)
2.2.4 Obsolescence
Obsolescence continues to be an important point of concern in most offshore
installations due to speed of development in technology. Obsolescence most of
the times influences electrical equipment instrumentation and control systems.
(Wright, 2011) It is aided by three principal determinants namely; technological
development speed, suppliers’ survival and expertise availability. (Habrekke,
Bodsberg, Hokstad, & Ersdal, 2011)
2.2.5 Organisational Issues
Organizational issues deals with practice and means in which the organization
handles ageing issues. It has to do with responsibilities handling, technical
abilities and knowledge transfer between personnel. In the situations of re-
organization, personnel ageing or inadequate knowledge transfer, the ageing
management process is affected negatively. In order for this to be mitigated, the
following can be done:
• Better organization of duty holders for ageing management and asset life
extension.

16
• Manpower should be resourced and satisfactory resources should be put
in place for ageing management and asset life extension.
• Clear allocation of roles and responsibilities to personnel involved.
• Personnel involved in every action that has to do with maintenance,
ageing management, asset life extension etc. have to be properly trained.

17
3 REVIEW OF AGEING MANAGEMENT
In order for platforms to continue functioning properly even after they exceed
their design life, ageing which is an inevitable process in such installations
needs to be properly managed with the right management procedures being
utilized. Some steps taken towards ageing management are discussed below.
3.1 Asset Life Extension
Making use of an offshore installation way past its design life does not imply
that the installation is ill-equipped for usage, a platform that is ageing can be
utilized as an export hub or can be used for processing works. (Hudson, 2008)
The complexity and the high expenses involved in decommissioning platforms
(Anthony, Ronalds, & Fakas, 2000) makes life extension the most reasonable
alternative. (Galbraith, Sharp, & Terry, 2009) Asset life extension essentially
has to do with establishment of a blueprint with which all conditions of asset
risks can be managed. The duration of asset life extension depends on the
ability of the facility to maintain technical, operational, and organizational
integrity. (Hokstad, Habrekke, Johnsen, & Sangesland, 2010)
One important element to consider during life extension is the combination of
organizational, personnel competence, regulations and reduction or mitigation
of environmental loads. Operators of a facility have the opportunity to establish
organizational guidance from the beginning of the life extension process when
they can combine the above mentioned elements. The figure below is a
flowchart illustration of factors to be considered when coming up with an
organizational context for life extension.

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Asset life extension methodology has to focus on two aspects:
 The efficacy of the management system
 The integrity of the asset dependent on current and imminent demands.
Oil production and processing equipment are situated on the platform. Platforms
are made up of the topside and the structure. The basic mechanism on a
platform whether fixed or floating is the structure. The predominant type of
platform being used especially in the North Sea is the steel jacket platform. The
jacket construction consists of tubular joints and braces which joints are highly
expensive and cause difficulty during design, fabrication and maintenance of
offshore structures due to the fact that they are very important to stability
maintenance and are very prone to fatigue. (El-Reedy, 2002) Figure 3-2 below
is an illustration of different types of offshore production platforms including
ship, semi-submersible, jack-up rig, spar etc.
Preparation or
context
establishment
Competent work Regulations
Organizational
policy
Figure 3-1: Organizational context development considerations

19
Figure 3-2: Offshore Production Platforms (Moan, 2005)
The figure below (figure 3-3) shows a typical steel jacket platform. They are
predominantly used in the North sea and require life extension procedures as
they are required to continue operation beyond their design life and are
susceptible to ageing.
The steel jackets are made of tubular joints and braces which are very
susceptible to failurThese failures occur as a result of stress when ageing is not
properly managed. Figure 3-4 is an illustration of a tubular joint and brace.

20
Figure 3-3: Commonplace North Sea type steel jacket platform (STATOIL, 2013)
Figure 3-4: Tubular joints and braces illustration (El-Reedy, 2002)
An aggressive structural integrity management (SIM) is required for the life
extension of offshore platforms. Ageing is more progressive and active for
platform topsides. The life extension methods in this report would be peculiar to
jackets and structures. Nevertheless, the methods can be used on any type of
structure and appropriate regardless of geographical location.

21
3.2 Safety Critical Elements
The UK Health and Safety Executive defines SCEs as those components
whose failure would result in a fatal or catastrophic failure. They are
components of a structure which have the function to impede the repercussion
of a catastrophic failure or major accident event(Stacey, Birkinshaw, & Sharp,
2001) such as ship collision, fire outbreak, explosions, loss of stability,
helicopter crash, major mechanical failures, release of toxic substances etc.
(Ritchie, 2011) Safety critical elements are referred to as “barriers” in the
Norwegian regulations. Virtually, the whole jacket is itemized as a safety critical
element by most operators. The temporary refuge and helideck are examples of
topsides safety critical elements. (Stacey, Birkinshaw, & Sharp, 2001)
3.2.1 Performance Standards
Hazards are managed using the performance standards of safety critical
elements and their sub-components as a standard. Performance standards
could either be quantitative or qualitative; this depends on the safety critical
element that is being qualified. (Awai, Azad, & Marri, 2006) However,
performance standards must not be vague and unclear and must qualify safety
critical elements based on the following:
• Functionality
• Equipment availability
• Reliability
• Survivability of the SCE
• Interdependency or reliance on other systems for function.
3.2.2 Development of Ageing SCEs Management Structure
One of the key problems peculiar to offshore industry is the insufficiency of
complete or comprehensive structures for managing ageing SCEs. This report

22
provides maintenance guidelines and ways to mitigate environmental loads to
aid proper management of ageing SCEs.
The SCE management structure is divided into six stages as shown by the
figure below:
After taking the above procedures, it should be determined if the chosen
maintenance or management approach is feasible, if not, plans should be made
for decommissioning.
TAKE NOTES OF
ENVIRONMENTAL LOAD
IMPACTS ON SCEs
CONTEXT PREPARATION
DECIDE MAINTENANCE
POLICY
AGEING SCEs
IDENTIFICATION
MONITOR AGEING SCEs
PERFORMANCE
IDENTIFY FACTORS
AFFECTING ASSET LIFE
Figure 3-5: Illustration of procedures for SCEs management

23
3.3 Maintenance of Physical Asset
Maintenance can be explained as all practical and organizational activities
carried out in order to return a structure to its original good functional condition.
Maintenance can be very expensive, whether financially or safety-wise. A
number of accidents have been as results of maintenance activities and
maintenance procedures have accounted for cause of 27% of injuries sustained
in the offshore oil and gas industry. (HSE, 2001) Maintenance cost makes for
60% of the total cost of operating offshore oil and gas installations. It is
therefore very important for the intricacies of maintenance to be understood.
(Ostebo, Olav, & Heggland, 1992)
The progress from corrective to preventive maintenance was very critical. This
involved the application of reliability engineering and was very necessary in
order to cut costs on maintenance procedures and to gain high conformities.
(Boznos & Greenough, 1998)
1. Corrective maintenance is action carried out after identification of a
failure and it requires highly skilled operators to carry it out.
2. Preventive maintenance is action carried out regularly at specific times in
order to decrease the PoF of a particular part or equipment. Preventive
maintenance is condition based.
Condition based maintenance (CBM) analyses the component’s condition in
order to carry out effective maintenance. It is used to detect any
commencement of an accident or breakdown by analysing a series of delicate
parameters such as vibrations and temperature. A little deviation in any of the
parameters could be an indication of probability of future accidents. (Wilmott,
1994) Proactive maintenance is also an aspect of preventive maintenance that
is based upon an approximated time of functional mishap. (Narayan, 2004)
3.3.1 Modern Maintenance Techniques
The world has become very technologically advanced and as a result assets
have become more programmed and computerized. As a result of this, every

24
system component must be in very ideal working condition due to the fact that a
minor failure can lead to a breakdown. This has led to development of
maintenance strategies. Reliability engineering and risk analysis are used to
improve asset integrity and decrease cost of maintenance. (BSI, 1993)
In the Risk based method, energy used in inspection is focused mainly on very
crucial systems. This method has been around for quite some years in the
offshore oil and gas sector. Both maintenance and inspection procedures are so
much similar but employ risk based ranking of activities made use of for
maintenance and inspection.

25
4 STRUCTURAL INTEGRITY MANAGEMENT (SIM)
4.1 Overview
The goal of a structural integrity management structure is to observe and
ensure a platform’s fitness-for-purpose. (Piva, Latronico , Sartirana, Gabetta , &
Nero, 2013) SIM is a continuous process (Stacey, Sharp, & Birkinshaw, 2008)
that is carried out sequentially and through the life cycle of a platform.
(Westlake, Puskar, O'Connor, & Bucknell, 2006) It provides a relationship
between evaluation procedure and inspection method during design,
fabrication, operation/checks, re-evaluation and decommissioning stages.
(Galbraith, Sharp, & Terry, Managing Life Extension in Ageing Offshore
Installations, 2005) Different operators take up distinctive approaches and it can
be executed or achieved from any stage. This can be seen in figure 4-1 below.
4.2 Elements of SIM
The elements of a good SIM framework are discussed below.
DATA EVALUATION STRATEGY PROGRAM
Managed system
for archive and
SIM data
retrieval and
more important
records.
Assessment of
structural
integrity
together with
fitness for
purpose;
development
of corrective
methods.
General
inspection
principles and
methods with in-
service
inspection
criteria.
Precise work
scopes to aid
inspection and
offshore
execution to
obtain correct
info.
Figure 4-1: SIM flowchart (Dinovitzer, Semiga , Tiku, Bonneau, Wang, &
Chen, 2009)

26
4.2.1 Data Management
This is a very crucial element of the life extension process. This is due to the
fact that the amount and quality of data available is the basis for the extent of
certainty of results. (Biasotto & Rouhan, 2011) The data required falls into:
(Westlake, Puskar, O'Connor, & Bucknell, 2006)
• Characteristic data that can show structure’s age, water depth design
data etc.
• Condition data, contains info showing alterations to the characteristic
data in the course of platform operation (platform alterations, damage etc).
4.2.2 Evaluation (Assessment)
Evaluation is carried out during the whole life cycle of a platform by gathering
data from outcomes of incidents, on-line monitoring systems, platform
alterations etc. (Solland, Sigurdsson, & Ghosal, 2011). A platform’s fitness-for-
purpose is determined through evaluation. Evaluation may depend on
repercussion of platform breakdown, risk of platform breakdown and
prerequisite for platform evaluation. (Sambu Potty, Akram, & Kabir, 2009) There
are different approaches to platform evaluation or assessment and they are
outlined below.
4.2.2.1 Design Level Analysis
Design level analysis uses linear means to represent every component of the
platform identical to the method employed in the construction of new platforms.
Platforms get constructed on an element-basis; aggregate of loads
administered onto the platform system to ascertain the highest internal forces in
every brace component. An acceptable or allowable strength is thereafter
allocated to each component and joint in the system. If all of the distinctive
members meet the requirements, the structure is considered fit for the chosen
standard. (Stacey & Sharp, Safety factor requirements for the offshore industry,

27
2007) Nevertheless, if one component fails to satisfy the requirements, it is
concluded as non-compliance. (Nichols, Goh, & Bahar, 2006) However, this
method results in some control of strength evaluation due to non-consideration
of material changes over time although platform generated is mostly stronger
and can withstand damage more than originally imagined. (Solland, Sigurdsson,
& Ghosal, 2011) Still, when it has to do with non-compliance, more cutting-edge
analyses are required. (O'Connor, Bucknell, DeFranco, Westlake, & Puskar,
2005)
4.2.2.2 Refined Analysis (Engineering Evaluation)
Refined analysis may be carried out for when SCEs don’t the design level
specifications. These types of structural evaluations aid in deciding if
strengthening or repairs are needed or if the current situation is fit-for-operation.
They usually include deformation analysis that is non-linear to decide ultimate
limit scale (ULS) of platform which is the highest amount of loading that can be
withstood without breakdown even when there is damage. (Nichols, Goh, &
Bahar, 2006) Most times, ageing affects the ULS, but ULS can also be
influenced by a decline in reserve strength as a result of cracks. (Stacey, Sharp,
& Birkinshaw, 2008)
In light of the fact that in-service inspections can only be used to assess local
platform degradation, (Piva, Latronico , Sartirana, Gabetta , & Nero, 2013)
ultimate strength can be resolved using reserve strength ratio (RSR) as a basis.
The reserve strength ratio is the ratio between the highest amount of loading
bearable by a structure based on analysis and the characteristic loading. The
reserve strength ratio is highly determined by the redundancy factor of the
structure. (Westlake, Puskar, O'Connor, & Bucknell, 2006)

28
4.2.2.3 Reliability Analysis
Even though refined analysis methods confirm that a platform is fit-for-use as
regards to resistance and severe loads, they appear not so valuable when
fatigue resistance is being assessed. Fatigue reliability analysis (FRA) is carried
out upon welded joints utilizing ISO 19902 or DNV codes or DNV codes for
tubular and non-tubular joints accordingly in order to enact a strategy on routine
inspections depending on an improved risk-based approach (Hokstad,
Habrekke, Johnsen, & Sangesland, 2010) by observing the actual possibility of
fatigue failure on platform joints (illustrated in figure 4-3).
FE Modelling
Analysis
Code checking
Verification
Analysis
FE modelling
Software
validation
Frame
geometry
Component
failure
criteria
System’s failure
mode
Frame
geometry
Component
behaviour
Figure 4-2: Normal design analysis (left), refined analysis (right)
procedures. (O'Connor, Bucknell, DeFranco, Westlake, & Puskar, 2005)

29
YES
NO
4.2.2.4 Fracture Mechanics (FM) Assessment
Fracture mechanics evaluation is a supplementary means for detailed
examination of cracks with reference to the spreading speed for the sake of
determining if corrective measures are needed (figure 4-4). (Piva, Latronico
, Sartirana, Gabetta , & Nero, 2013) Probabilistic fracture mechanics is
carried out to gain knowledge of the connection between the probability of
failure of an element and its operational life by computing the lingering or
residual FL beyond a TT crack. (Moan, 2005)
ESTIMATIONS OF
FATIGUE RELIABILITY β
FOR EACH JOINT
PLAN OF NEXT
INSPECTION
IDENTIFICATION OF
CRITICAL JOINTS
(β˂βtarget)
CHOICE OF JOINTS FOR
INSPECTION
INSPECTION
RELIABILITY UPDATING
CHOICE OF SUB-SET OF
CRITICAL JOINTS
RELIABILITY UPDATING
CONSIDERING “NO CRACK
FOUND” SCENARIO FOR
EACH JOINT OF THE SUBSET
ALL JOINTS
OVER
RELIABILITY
TARGET?
Figure 4-3: Joint selection for inspection (Piva, Latronico ,
Sartirana, Gabetta , & Nero, 2013)

30
Figure 4-4: Fracture mechanics approach (Marshall & Copanoglu, 2009)
4.3 Strategy
The outcomes of all the analyses are implemented to come up with a
comprehensive inspection principle. The ISO procedure provides principles for
in-service inspection. (Stacey, Sharp, & Birkinshaw, 2008)
There is a feedback into the in-service database from the inspection,
maintenance and repair (IMR) plan. The IMR plan is a live document and is
made up of the following: (Westlake, Puskar, O'Connor, & Bucknell, 2006)
• A basic standard inspection following platform installation.
• Routine/regular inspections to monitor deterioration.
• Distinctive inspection in response to unexpected damage or severe
loading circumstances.
Inspection involves the routine and consistent monitoring of a structure by
checking for flaws or possible flaws through analyses. Maintenance is
discussed in 3.3. An example of a maintenance activity is the planned

31
replacement of sacrificial anodes. Repair has to do with activities done in order
to recover a structure to appropriate working condition after damage has been
recognized. (Dinovitzer, Semiga, Tiku, Bonneau, Wang, & Chen, 2009)
4.4 Program
The program stage of the SIM plan has to do with the establishment of an ideal
plan to aid data input back into the procedure for future improvements since the
procedure is a constant cycle. (Westlake, Puskar, O'Connor, & Bucknell, 2006)
Determinants of a SIM program include documentations of procedure,
personnel competence and behaviour, survey tools/methods, and method of
distribution. Inspection records also have to be accurate and consistent.
(Sambu Potty, Akram, & Kabir, 2009)

33
5 RISK BASED INSPECTION
5.1 Overview
Inspections can either be general or precise in nature and can differ in level;
precise inspections are usually more expensive and commonly needed more by
ageing structures. Planning of inspection can be a difficult process and
inspection of underwater components is unrealistic taking into mind the cost.
Therefore, planning of inspection is appropriate.
A risk assessment aids with the methodical approach with restructuring of
workforce, assets, environment and identity. Risk assessment outcomes should
aid in deciding ways to carry out control, prevention and mitigation activities.
The guidelines to improvement of safety, health and environment management
structure are:
 Risk identification
 Risk evaluation
 Risk analysis
 Risk treatment
 Monitoring and review.
It is very crucial to pinpoint the types of risks that can be tolerated. For a new
design, there are many methods that can be employed for risk prevention. But
for an already existing structure, the range can be minimized. Common risk
prevention methods include prevention, elimination, control, mitigation and
restoration. The best method in getting rid of hazards is the elimination method
but it is not always possible. The most economical method should be applied for
risks that cannot be gotten rid of completely. (HSE, 2010) The figure below is a
reliability based maintenance framework as stipulated by ISO

34
Figure 5-1: Reliability based maintenance framework based on ISO 3100
Table 5-1: Examples of inspection methods. (Animah, 2012)
Level Inspection
methods
Attributes
1 General visual
inspection
(GVI) above
water.
Detects the existence of excess corrosion, seabed
scour, and excess fatigue damage.
Normally not expensive.
Takes care of jacket structure inspection, service
conductors, well bay framing conductors, risers, CP
hardware and seabed.
Cleaning of structural elements not needed.
Can be performed quickly.
2 GVI above and
below water.
Close visual
inspection
(CVI).
Flooded
Performed to inspect structure critical areas.
Focused on detecting damage hidden by surface
contamination.
Requires pre-cleaning and simultaneous cleaning.
It can take a lot of time and is peculiar to critical
areas.

35
member
detection
(FMD).
Cathodic
potential
measurement
(CPM).
3 Close visual
inspection.
Magnetic
particle
inspection.
Eddy current
inspection.
Alternating
current field
measurement.
Ultrasonic
testing.
Radiographic
techniques.
Highly detailed inspections.
Usually done to get data required for structural
evaluation.
Non-destructive techniques are used.
Highly qualified personnel required.
Cleaning, training and testing requirement levels
depend on type of damage to be inspected and type
of equipment used.
The table above shows different inspection methods that can be used to assess
the risks in an installation. The methods vary according to risk and nature of
inspected component.
5.2 RBI Model
The risk-based method is a development on the customary method of
maintenance which depends on the probability of failure (PoF) but not the
consequence of failure (CoF). In the RBI model, the commercial or monetary
risk is calculated with respect to the PoF and financial repercussions. (Goyet,
Straub, & Faber, 2002) (Biasotto & Rouhan, 2011) The risk-based approach
can be used to determine suitable inspection techniques. The process involved
is illustrated below.
The final outcome of the RBI is an inspection plan that precisely shows the
number of inspection activities to be performed, inspection times, qualities of
inspections and the method of mitigation having to do with damage detection.

36
STRUCTURE COMPONENT CLASSIFICATION
EVALUATION AND CALIBRATION OF COMPONENT POF
RE-ASSESSMENT OF POF ASSUMING INSPECTION IS CARRIED OUT IN
FUTURE
IDENTIFY APPROPRIATE SUBSTITUTE INSPECTION METHODS, IMPLEMENTING
ASSESSMENTS ON THE GENERAL RISK
ASSESMENT OF COMMERCIAL OF BREAKDOWN FOR EACH COMPONENT
EVALUATION OF HSE AND COMMERCIAL CONSEQUENCES RELATED TO
PLATFORM BREAKDOWN
QUALITATIVE EVALUATION OF SAFETY, HEALTH AND ENVIRONMENT
HAZARDS AND BLENDING WITH THE DEVELOPED POF
Figure 5-2: The RBI process

37
6 CASE STUDY
6.1 Case Study on Hurricane Ivan’s Damage on Offshore
Structures in the GOM
In the last decade, Ivan has been one of the hurricanes to cause great damage
to offshore installation in the Gulf of Mexico (GOM). It made landfall in the GOM
in September 2004 causing damage to several offshore installations. Other
hurricanes that have caused extensive damage are Lili, Katrina and Rita. These
hurricanes have helped decide the efficacy of present design standards and
regulations of installations and helped develop propositions for alterations, if
any is required.
In this report, the results of Ivan are used to find out how fixed ageing platforms
in the GOM react to hurricanes. Both quantitative and qualitative analyses are
employed. In the qualitative assessment, a review of damages to jackets and
topsides including general trends such as number of platforms damaged and
their ages. The quantitative assessment compares the actual response of
platforms to Ivan to what was predicted by API RP 2A using analytical response
as a reference. That is to say, if a platform got destroyed, it is checked if it was
predicted by API RP 2A and the results are compared to those of Hurricanes
Andrew and Lili.
6.2 Results
6.2.1 Qualitative Assessment
The data obtained for this assessment included post-Ivan inspection results,
structural evaluations, repair reports as well as general information from the
Minerals Management Service (MMS) database.
Hurricane Ivan resulted in the damage of seven platforms in the GOM. One
platform damage was due to mudslide as a result of the hurricane while the
other six were due to environmental loads such as wind, waves and currents
going beyond the withstanding capacities of the platforms. It is noteworthy to

38
know that extra platforms might have been decommissioned later due to
Hurricane Ivan damages.
Several other platforms sustained different degrees of damages as a result of
Ivan in addition to the seven core platform damages. Table 6-1 below illustrates
a list of fixed platforms damaged by Hurricane Ivan. Some of the damages to
the platforms were not surprising as most of the failed platforms were beyond
their design lives and were already ageing. This implies that most of the
damages sustained by them were due to ageing as they were older vintage
structures. They largely had low strength properties such as weaker joints and
weaker brace bracing patterns than platforms designed to current industry
regulations. Also, the topside deck heights for these ageing platforms were
lower making them prone to wave-in-deck that increased platform loads way
above the platforms’ ultimate capacity. Nonetheless, the level of topside
damage both structural and non-structural on many of the platforms showed
that Ivan resulted in very large waves and related wave peak heights larger than
estimated.
Fixed platform data showed that most failed platforms from Ivan were situated
in water depths between 200 to 350 feet with deck heights below the present
API recommendations. The resulting damages included topside damages (as a
result of winds and wave-in-deck), jacket leg buckles and separations, bracing
failures, joint failures and conductor bracing failures.
Table 6-1: Fixed platforms destroyed by Hurricane Ivan (Energo Engineering Inc.,
2005)
No
.
Are
a
Blo
ck
Operator Wate
r
Dept
h (ft)
Year of
Installati
on
Exposu
re
Catego
ry
Deck
Heig
ht (ft)
Structu
re type
Dam
age
categ
ory
1 MC 20 A Taylor
Energy
Company
475 1984 L1 49 8-P destr
oyed
2 MP 98 A Forest Oil
Corporatio
n
79 1985 L1 57.5 TRI destr
oyed
3 MP 293 A Noble 247 1969 L2 45 8-P destr

39
Energy,
Inc.
oyed
4 MP 293 SONAT Southern
Natural
Gas
Company
232 1972 L2 42 4-P destr
oyed
5 MP 305 C Noble
Energy,
Inc.
244 1969 L2 46 8-P destr
oyed
6 MP 306 E Noble
Energy,
Inc.
255 1969 L2 46 8-P destr
oyed
7 VK 294 A Chevron
U.S.A. Inc.
119 1988 L2 32 B-CAS destr
oyed
8 MP 296 A GOM
Shelf LLC
212 1970 L2 46 8-P major
(A
9 MP 277 A El Paso
Production
Oil & Gas
Company
223 2000 L2 50.3 4-P major
(A
10 MP 279 B Dominion
Exploratio
n &
Production
, Inc.
290 1998 major
(A
11 MP 138 A Newfield
Exploratio
n
Company
158 1991 L2 55 4-P major
12 MP 311 B GOM
Shelf LLC
250 1980 L2 39.5 8-P major
13 MP 296 B GOM
Shelf LLC
225 1982 L2 49.2 8-P major
14 SP 62 A Apache
Corporatio
n
340 1967 L2 40 8-P SK major
15 SP 62 B Apache
Corporatio
n
322 1968 L2 44 8-P SK major
16 SP 62 C Apache
Corporatio
n
325 1968 L2 48 8-P SK major
17 VK 900 A Chevron
U.S.A.,
Inc.
340 1975 L2 46.3 8-P major
18 MP 281 A Dominion
Exploratio
n &
Production
, Inc.
307 50 4-P major
19 MP 289 B Apache
Corporatio
n
320 1999 L1 45 8-P major
20 MP 290 A Apache
Corporatio
n
289 1968 L2 42 8-P major
21 MP 305 A Noble
Energy,
180 1968 L2 45 8-P major

40
Inc.
22 MP 305 B Noble
Energy,
Inc.
241 1969 L2 46 8-P major
23 MP 306 D Noble
Energy,
Inc.
255 1969 L2 46 8-P major
24 MP 306 F Noble
Energy,
Inc.
271 1978 L2 49 4-P SK major
25 VK 786 A-
Petroniu
s
Chevron
U.S.A. Inc.
1754 2000 L1 55 C-
TOWER
major
26 VK 780 A-Spirit Apache
Corporatio
n
722 1998 L1 49 4-P minor
27 VK 823 A-Virgo TOTAL
E&P USA,
INC.
1130 1999 L1 47 OTHER minor
28 MP 261 JP Williams
Field
Services -
Gulf Coast
Company
299 2001 minor
29 MP 298 B-
VALVE
Southern
Natural
Gas
Company
222 1972 L2 43 4-P minor
30 MP 144 A Chevron
U.S.A.,
Inc.
207 1968 L2 52.2 4-P minor
31 MP 252 A Shell
Offshore
Inc.
277 1990 L2 50 4-P SK minor
32 MP 280 C Dominion
Exploratio
n &
Production
, Inc.
302 1998 minor
33 SP 60 D SPN
Resources
, LLC
193 1971 L2 49 8-P minor
34 VK 989 A-
Pompan
o
BP
Exploratio
n &
Production
Inc.
1290 1994 L1 55.8 4-P SK minor
6.2.2 Quantitative Assessment
The bias factor is employed in the quantitative assessment. Bias factor is a
quantity that gives the ratio between true and estimated capacity of an offshore
platform in accordance with API RP 2A analysis. If a platform withstands a
hurricane in contrast to API estimations, it is allocated a bias factor higher than

41
1.0 which is calculated using all known safety determinants in the API
approach.
The bias factor was calculated for Hurricane Ivan paying attention to six
platforms. Generally, the quantitative assessment for Ivan shows a bias factor
of about 1.0 indicating that API RP 2A is doing a somewhat moderate job in
estimating platform performance.
6.2.3 Recommendations from Case Study
1. Investigate the minimum deck elevation curves for design of new
platforms contained in API RP2A and for assessment of existing platforms.
2. Investigate the possible changes to the 100 year wave height curves in
API RP2A used for new design contained in API RP2A and for assessing new
platforms.
3. Investigate damage to secondary structural members such as conductor
trays and riser clamps and provide design guidance.
4. Investigate specifically the destroyed platforms in Ivan in order to
understand how the failures occurred and how they could have been prevented.
5. Provide metocean instrumentation on fixed offshore platforms.
The figure below shows the course of Hurricane Ivan with positions of destroyed
fixed base platforms.

42
Figure 6-1: Hurricane Ivan path showing locations of destroyed platforms
(Energo Engineering Inc., 2005)

43
7 DISCUSSION
7.1 General discussion
The issue of ageing offshore structures is very crucial to the offshore industry
and it seems it would continue to be a very crucial matter with the increasing
number of ageing offshore structures. This importance of ageing is shown more
and more in the subject matter of present laws and recommended practices
which emphasize that ageing of offshore structures be considered specifically.
Structural integrity management for ageing offshore structures is obviously a
complicated procedure. Ageing infrastructure performance would vary as
degradation occurs at different stages of the life courses. This actually depends
upon the structural layout, construction quality, inspection during use and
repairs and the nature and degree of structural evaluation. Another point in
question that adds to the complexity of the structural integrity management of
these ageing structures is degradation which occurs without being detected due
to insufficient inspection and or due to the fact that the part cannot be
inspected.
Ageing is therefore dependent upon a large amount of uncertainties. As a
result, accurate information is needed on the performance of ageing offshore
installations. Fatigue strength and system strength of these structures must be
well understood including a good understanding and implementation of
inspection techniques that would give correct information on structural condition
of these installations. In order for ageing offshore structures to be managed
efficiently or adequately, inspection, maintenance and structural analysis
methods must be carried out adequately.
Over the years, several studies have been carried out to assess the
performance of offshore installations. A good number of these researches have
been employed in establishing present standards and guidance for the use of
offshore structures. Getting to understand materials and structural performance
is a continuous process. Know-how, techniques and assessment procedures

44
are improved upon by making use of information made available as offshore
installations age. Decommissioned structures can be inspected to obtain
important info on structural and materials performance for every type of part,
especially those parts that are usually difficult to inspect.
Getting familiar with the performance of materials and structures is a continuous
process. As offshore structures continue to age, available information need be
employed to advance knowledge and evaluation procedures. Carrying out
inspections on structures that have been decommissioned would provide
beneficial knowledge on performance of materials and structures.
Lately structures that have reached their life extension stages are being dealt
with similar to structures within original design life. However, the emphasis
placed on life extension in current regulations, codes and standards has aided
life extension and ageing management to be taken more seriously in the
offshore industry. Also, the putting together of an adequate structure for SIM
would aid ageing management and life extension.
7.2 Problems Associated with Ageing
There are quite a number of problems associated with ageing. I break them into
financial, environmental and biological issues. The financial issues deal with the
cost of replacing worn out parts and the expenses incurred during management
and life extension. The environmental issues are environmental hazards as a
result of damaged structures due to ageing such as oil spillage and
hydrocarbon leaks. The biological issues include loss of human lives and
extinction of organisms due to habitat contamination.
7.3 Limitations to Ageing Management and Asset Life
Extension (Challenges)
The following can be considered limitations to asset life extension: (Wintle &
Sharp, 2008)
 Failing to disclose an original design life or estimated added operating
life.

45
 Failing to cite fitness-for-service of SCEs.
 Records Hydrocarbon leaks and safety warnings as a result of ageing.
 When safety critical systems model and structure are not up-to-date.
 Failing to focus on uncompleted important maintenance activities for
SCEs.
 Uninspectable elements undetectable deterioration to SCEs.
 Incompetent integrity management organization.

47
8 CONCLUSION
This report has analysed how ageing and degradation can influence different
components of an offshore structure and the installation as a whole. Also, a
review of ageing and degradation mechanisms has been carried out.
From this report, it can be noted that ageing assets management does not only
have to do with equipment but also paying attention to management systems.
When the management system is adequate before concentrating on equipment
life, it may help reduce equipment replacement in the long run due to the fact
that equipment focused ageing management gives short term satisfaction.
Proactive methods are the best methods for ageing management and a good
ageing management system begins even before degradation begins.
Ample effort has been put into ageing management in the offshore oil and gas
industry. Nevertheless, more work is required to be directed towards ageing
management plus asset life extension. Life extension of offshore installations is
achievable when structural integrity is properly managed. Integrity indicators
and risk factors are the foundations for life extension. However, for life
extension to be successful, close attention has to be paid to obsolescence and
technical know-how of workforce. Also, identification and proper management of
SCEs help increase reliability of offshore structures.
During this research I observed that due to high amount of work load, less time
and attention is given to asset life extension. There exist therefore urgency for
greater awareness of ageing with proper life extension plans and practices put
in place.

49
REFERENCES
Animah, I. (2012). Managing ageing safety critical elements for life extension in
oil and gas industry (MSc Thesis, Cranfield University).
Anthony, N. R., Ronalds, B. F., & Fakas, E. (2000). Platform decommissioning
trends. SPE Asia Pacific oil and gas conference and exhibition, Vol. SPE
64446, (p. 1). Brisbane, Australia.
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53
APPENDICES
Appendix A Probability of Failure Assessment
The probability of failure assessment is broken down into two phases;
approximation of the PoF due to fatigue, and the PoF due to other means.
(Barton & Descamps, 2001) For PoF due to fatigue, an increase in the PoF as
time goes on is shown using probabilistic assessment and cumulative effect.
For the PoF due to any other means, effects of the determinants of the PoF are
evaluated by using engineering judgment and historical data. These
determinants include fabrication flaws, in-operation flaws, stationary loading,
marine growth and origin of material. These determinants are given a 0 to 1
rating; this rating shows an impact level of naught up to very high.
Table A-1: Assessment of PoF due to individual influencing determinant (Barton
& Descamps, 2001)
Impact
Level
Very High High Moderate Low Nil
Relative
Probability
Level
1 ¾ ½ ¼
0
Calibrations are afterwards carried out in two phases. These calibrations are
performed to get absolute component PoF values.
The first phase involves locating an analysis of the influencing determinants
excluding fatigue gotten from the data for the geographical location of the
platform. Afterwards, a summation of the partial relative values is done. The
summation is carried out based on expected repetitiveness of flaws for the
element type. (Barton & Descamps, 2001)

54
The second calibration phase has to do with regularly inspected structures.
Calibration determinants are assessed from data gotten from the average
number of breakdowns that occur for each year and are utilized in calculating
the annual PoF peculiar to each element. In order to make calibration
productive, components can be arranged in accordance with identical
repetitiveness of defects. Examples of such groupings include:
 Jacket tubular members
 Conductor guide frame (CGF) elements
 Service conductor accessories and supports
 Impressed current anode conductors (ICAC) and supports.
Due to the fact that calibrated probabilities are actually small, they are updated
cumulatively in order to examine the time-dependent property of the failure
mechanisms. The probability of fatigue failure is given below:
( ) ( )
( )
Equation 1
Where
P () = PoF
T2 = variable denoting time to TT cracking
t = time at which probability of failure is calculated
NFL = welded joint’s normal FL
= standard normal cumulative distribution function
Probability of fatigue failure based on prior inspection statistics is updated using
the Bayesian updating techniques. Following each inspection, the probability of
FF is updated using the formula below.

55
( )
( ) ( )
( )
Equation 2
Rinsp = Reliability of the inspection
t2 = time at which PoF is calculated
INSP Ratio = ratio between time to TT cracking and time to reach a defect size
detectable by the inspection methods.
Ratios derived from the fatigue analysis database for typical inspection
methods are presented in table 6 below. The notional or imaginary probability of
detection (PoD) of the inspection methods are deduced using these ratios.
Table A-2 below depicts reliability and estimated costs for MPI and CVI.
Table A-2: Inspection ratios for typical inspection methods (Barton & Descamps,
2001)
INSPECTION
TECHNIQUE
INSP
RATIO
RELIABILITY OF TECHNIQUE
MPI 3 90%
CVI 2 90%
FMD 1 90 (10% for brace member, 80% for chord member)
GVI 0.75 60%

56
Table A-3: Reliability and cost estimates for CVI and MPI (Marshall & Goldberg,
2009)
CVI limited
cleaning (black
oxide)
CVI complete
cleaning (bare
metal)
MPI limited
cleaning (black
oxide)
MPI
complet
e
cleaning
(bare
metal)
Detectable crack length 12” and higher 12” and higher 1” and higher 1” and
higher
Detectable crack width 0.006 inches
and higher
0.002 inches
and higher
0.001 inches
and higher
0.001
inches
and
higher
Detectable crack depth 0.03 inches
and higher
0.03 inches
and higher
0.03 inches
and higher
0.03
inches
and
higher
Cleaning time 3-5 min/sq. ft. 10-30 min/sq.
ft.
3-5 min/sq. ft. 10-30
min/sq.
ft.
Estimated relative
cost/ft.
1.0 1.8 1.2 1.9
Crack detecting
reliability
4’Lx0.001”Wx0.03”D
5% 20% 80% 80%
Crack detecting
reliability
12”Lx0.01”Wx0.03”D
75% 80% 90% 90%
Crack detecting
reliability
24”Lx1”Wx3/8”D
90% 90% 90% 90%
A.1.1 Assessment of Failure Consequence and Risk
The repercussions of failure of components due to ageing are evaluated in
reference to their impact on the platform and appurtenance integrity. It is worth
noting that repercussions are assessed qualitatively. An example of
consequence or repercussion rating is portrayed in the table below.

57
Table A-4: Example of qualitative consequence rating (Animah, 2012)
CONSEQUENCES
Category Low (1) Medium (2) High (3)
Safety:
Functional failure
When the likelihood
of injuries is low.
When likelihood for
fire explosion is
absent.
When likelihood for
lost time due to
injuries is present.
If failure effect on
SCEs’ functionality is
limited.
When there is
likelihood for serious
injuries.
When SCEs are made
non-functional.
Safety:
Containment failure
When non-
flammable medium is
present.
When operational
temperature and
pressure are normal.
When ignitable
medium is under
flash point.
When temperatures
and pressures of
medium is extreme.
When ignitable
medium is over
flashpoint.
When temperatures
and pressures of
medium is very
extreme.
Production When minimal
production loss is
present.
Where failure will
slow down
production and affect
it by 20%.
When there exist an
immediate and
significant loss of
production and
revenue.
In keeping risks as low as reasonably practicable (ALARP), it is more sensible
to make use of the utmost risk instead of the average risk of failure. This means
that, it makes more sense to keep risk of failure not beyond acceptable extents
by carrying out routine inspections instead of allowing vast variations by
carrying out precise inspection demarcated by years of minimal inspection.

58
Figure A-1: Comparing alternate inspection programs with same range but
different frequencies (Rouhan & Schoefs, 2003)
Maintenance activities are meant to be performed throughout the life cycle of an
asset, and the added value of every maintenance method or technique is
assessed before being put into use. The added value might vary due to how
and where it is applied or used and is not always financial. Inspection generally
reduces the PoF although the CoF usually doesn’t change. Risk reduction is
given as: (Barton & Descamps, 2001)
* ( )
( )+
Equation 3
The total of the risk reductions for a particular inspection program provides a
view of the advantages of performing inspection activities. The added value of
inspection can be deduced as follows: (Barton & Descamps, 2001)

59
Equation 4
It is however imperative to note that the highest added value is gotten from the
most cost effective program. Nevertheless, there are other determinants
considered. In coming up with correct criteria, SHE and financial repercussions,
current and future maximum PoF and risk reduction are taken into
consideration.
The point at which extra spending results in just a little extra reduction in risk is
the ALARP point in the risk management decision procedure. The figure below
shows the process for choosing an inspection program for a platform. This
figure is a result of assessment done on 14 jacket platforms. The importance of
optimized inspection that applies to HSE and financial risk is depicted in this
figure.

60
Figure A-2: Risks related with alternative structural inspection programs for a
platform (Barton & Descamps, 2001)
Appendix B Important Ageing and Life Extension
Codes and Standards
The important ageing and life extension codes and standards are shown in
table B-1. API RP 2A (American) and the N-006 (Norwegian) standards show
usage of industry standards distinct to their regions and need to be added to for
use somewhere else.
Table B-1
LIFE EXTENSION
FEATURES
RELEVANT CODES, STANDARDS AND
RECOMMENDED PRACTICES
Assessment Issues ISO 2394, General principles on reliability for structures,
Chapter 8, Assessment of existing structures.
ISO 13822, Basis for design of structures, assessment of

61
existing structures.
ISO 19900, Offshore structures, General requirements,
Section 9 – Assessment of existing structures.
ISO 19902, Fixed structures, Section 25, Assessment of
existing structures.
API RP 2A 1997, Section 17, Assessment of existing
platforms (excludes life extension as an activator)
NORSOK N-004, Design of steel structures, Chapter 10,
Reassessment of structures.
DNV OSS 101, Special provisions for ageing mobile
offshore and self-elevating units.
Fatigue life
extension
ISO 19902, Fixed structures, Section A15 (Fatigue),
cumulative damage and extended life.
NORSOK N-004, Design of steel structures, section
10.2, Extended fatigue.
DNV RP C203, Fatigue strength analysis of offshore
steel structures, Chapter 5, Extended fatigue life.
ABS guide for the assessment of offshore structures.
HSE, Offshore information sheet 5/2007, Ageing semi-
submersible installations.
Corrosion
protection
NORSOK, Protection, M-503
DNV, Recommended practice, Cathodic protection
design.
Inspection,
maintenance and
survey
D.En/HSE Guidance notes – section on surveys.
API RP 2A section 14, surveys.
ISO 19902 section 24, In-service inspection and
structural integrity management.

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