CRANFIELD UNIVERSITY
OKEREKE, CHUKWUNONSO N.
AGEING OF OFFSHORE ASSETS: ISSUES AND CHALLENGES 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.
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.
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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.
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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
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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
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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, W estlake, & 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
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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
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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
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LIST OF EQUATIONS Equation 1 ........................................................................................................ 54 Equation 2 ........................................................................................................ 55 Equation 3 ........................................................................................................ 58 Equation 4 ........................................................................................................ 59
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LIST OF ABBREVIATIONS UKCS
United Kingdom Continental Shelf
ALARP
As low as reasonably practicable
ALE
Asset life extension
LE
Life extension
COF
Consequence of failure
CVI
Close visual inspection
DL
Design life
EDI
Eddy current inspection
FL
Fatigue life
FMD
Flooded member detection
FRA
Fatigue reliability analysis
GVI
General visual inspection
HSE
Health and safety executive
IMR
Inspection, maintenance and repair
MAE
Major accident event
MPI
Magnetic particle inspection
NS
North sea
GOM
Gulf of Mexico
POD
Probability of detection
PS
Performance standards
POF
Probability of failure
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RSR
Reserve strength ratio
PSA
Petroleum Safety Authority
SCE
Safety critical elements
SHE
Safety, health and environment
SIM
Structural integrity management
TT
Through-thickness
ULS
Ultimate limit scale
UT
Ultrasonic testing
CBM
Condition based maintenance
FM
Fracture mechanics
RBI
Risk based inspection
MMS
Minerals Management Service
DNV
Det Norske Veritas
Inc.
Incorporation
ISO
International Organization for Standardization
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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)
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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
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1.1 Ageing Scenarios The figure below gives clear knowledge of the different scenarios common to ageing offshore installations
AGEING
TIME-RELIANT PROCESS FATIGUE
DAMAGE ACCIDENTAL DAMAGE
CORRSION CREEP
ENVIRONMENTAL BURDEN GEOLOGICAL
EXTERNAL MODIFICATIONS NEW TECHNOLOGIES FAILURE TO ADAPT TO CHANGES
Figure 1-2: Ageing scenarios
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.
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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.
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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 5
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
perspectives.
These
ageing
include;
management
material
from
deterioration,
three
extensive
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
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the structure during the life extension phase. A huge safety margin indicates a longer life extension period.
AGEING MANAGEMENT
Material degradation Obsolescence
Organizational problems
Material features Operational situations
Equipment expired
Re-organization Personnel ageing
Environmental circumstances
New requirements
Maintenance methods
Advance in technology
Knowledge transmission
Figure 2-2: Ageing management (Hokstad, Habrekke, Johnsen, & Sangesland, 2010)
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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.
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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 timerelated 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
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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.
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Table 2-1: Structural components prone to corrosion (Galbraith & Sharp, 2007) Element
Risk management measures
Consequence of failure
Issues of life extension
Steel substructure
Cathodic Member or protection joint failure as system a result design. reduction in Regular wall checks, CP thickness. levels measurement, anodes replacement (if required).
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.
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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 throughthickness 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.
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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.
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Table 2-2: Structural parts prone to fatigue (Galbraith & Sharp, 2007) Element
Risk
Failure
Issues for
management
consequences
life
practices
extension
Substructurewelded 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 inservice 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.
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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 reorganization, 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.
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•
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.
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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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Preparation or context
Organizational policy
Competent
work
Regulations
Figure 3-1: Organizational context development considerations
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.
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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.
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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.
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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
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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:
CONTEXT PREPARATIO N
AGEING SCEs
IDENTIFY FACTORS
DECIDE MAINTENANCE
MONITOR AGEING SCEs
TAKE
NOTES
ENVIRONMENTAL
OF LOAD
Figure 3-5: Illustration of procedures for SCEs management
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.
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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
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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.
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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. 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 achieved from any stage. This can be seen in figure 4-1 below.
DATA Managed system for archive and SIM data retrieval and more important records.
EVALUATIO N Assessment of structural integrity together with fitness for purpose; development of corrective
STRATEGY
PROGRAM
General inspection principles and methods with inservice 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)
4.2 Elements of SIM The elements of a good SIM SI M framework are discussed below.
25
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-forfitness-forpurpose 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,
26
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)
27
FE Modelling
Frame geometry
Software
Component
validation
behaviour
FE modelling
Analysis
Frame geometry
Code checking
Analysis
Component failure criteria
Verification
System’s failure mode
Figure 4-2: Normal design analysis (left), refined analysis (right) procedures. (O'Connor, Bucknell, DeFranco, Westlake, & Puskar, 2005)
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) i s 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 fi gure 4-3).
28
ESTIMATIONS OF FATIGUE RELIABILITY β FOR EACH JOINT CHOICE OF SUB-SET OF CRITICAL JOINTS
IDENTIFICATION OF CRITICAL JOINTS
(β˂βtarget) RELIABILITY UPDATING CONSIDERING “NO CRACK FOUND” SCENARIO FOR EACH JOINT OF THE SUBSET
CHOICE OF JOINTS FOR INSPECTION
INSPECTION
ALL JOINTS OVER RELIABILITY
RELIABILITY UPDATING
YES
NO PLAN
OF
NEXT
INSPECTION
Figure 4-3: Joint selection for inspection (Piva, Latronico , Sartirana, Gabetta , & Nero, 2013)
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)
29
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
30
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)
31
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
33
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.
34
member detection (FMD). Cathodic potential measurement (CPM). 3
Close visual inspection. Magnetic particle inspection. Eddy current inspection. Alternating current field measurement.
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.
Ultrasonic testing. Radiographic techniques.
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.
35
STRUCTURE COMPONENT CLASSIFICATION
EVALUATION AND CALIBRATION OF COMPONENT POF
EVALUATION OF HSE AND COMMERCIAL CONSEQUENCES RELATED
TO
PLATFORM BREAKDOWN
QUALITATIVE EVALUATION OF SAFETY, HEALTH AND ENVIRONMENT HAZARDS AND BLENDING WITH THE DEVELOPED POF
ASSESMENT OF COMMERCIAL OF BREAKDOWN FOR EACH COMPONENT
IDENTIFY APPROPRIATE SUBSTITUTE INSPECTION METHODS, IMPLEMENTING ASSESSMENTS ON THE GENERAL RISK
RE-ASSESSMENT OF POF ASSUMING INSPECTION IS CARRIED OUT IN FUTURE
Figure 5-2: The RBI process
36
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
37
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
38
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
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
39
major (A
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
APetroniu s
Chevron U.S.A. Inc.
1754
2000
L1
55
CTOWER
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
29
MP
298
BVALVE
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
33
SP
60
D
SPN Resources , LLC
193
1971
L2
49
8-P
minor
34
VK
989
APompan o
BP Exploratio n& Production Inc.
1290
1994
L1
55.8
4-P SK
minor
minor
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
40
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.
41
Figure 6-1: Hurricane Ivan path showing locations of destroyed platforms (Energo Engineering Inc., 2005)
42
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
43
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.
44
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.
45
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.
47
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. Biasotto, P., & Rouhan, A. (2011). Feedback from Experience on Structural Integrity of Floating Offshore Installations. OTC Brasil, Vol. OTC 2436 (p. 1). Rio de Janeiro, Brazil: OTC, Rio de Janeiro, Brazi. Clock Spring Company. (2012). Offshore riser repair. Retrieved from http://www.clockspring.com/field-report-offshore-riser-repair Dinovitzer, A. S., Semiga , V., Tiku, S., Bonneau, C., Wang, G., & Chen, N. (2009). Practical Application of Probabilistic Fracture Mechanics for Structural Integrity Management. Offshore Technology Conference, Vol. OTC 19841. Houston, Texas. El-Reedy, M. A. (2002). Optimization study for the offshore platform inspection strategy. SPE international petroleum conference and exhibition, Vol. SPE 74404, (p. 1). Villahermosa, Mexico. Energo Engineering Inc. (2005). Assessment of fixed offshore platform performance in Hurricanes Andrew, Lili and Ivan. ESDEP
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accessed
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(n.d.).
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Galbraith, D. N., Sharp, J. V., & Terry, E. (2005, September 6-9). Managing Life Extension in Ageing Offshore Installations. Offshore Europe, Vol. SPE 96702 . Aberdeen, United Kingdom: Society of Petroleum Engineers. Galbraith, D. N., Sharp, J. V., & Terry, E. (2009, September 6-9). Manageing life extension in ageing offshore installations. Offshore Europe, Vol. SPE 96702 . Aberdeen, UK: Society of Petroleum Engineers. Galbraith, D., & Sharp, J. (2007). Recommendations for design life extension regulations. Goyet, J., Straub, D., & Faber, M. H. (2002). Risk based inspection planning. Revue Française de Génie Civil, vol. 6, no. 3, 486-503. Habrekke, S., Bodsberg, L., Hokstad, P., & Ersdal, G. (2011). Issues of consideration in life extension and managing ageing facilities. Hokstad, P., Habrekke, S., Johnsen, R., & Sangesland, S. (2010). Ageing and life extension for offshore facilities in general and for specific systems. SINTEF Report for The Petroleum Safety Authority Norway . HSE. (2010). Hudson, B. (2008). Platform and field life assessment and extension. Abu Dhabi internantional petroleum exhibition and conference, Vol. SPE 118157 , (p. 1). Abu Dhabi, UAE. Marsh, Z., & Selfridge, F. (n.d.). Corrosion management of ageing assets from the operator's perspective, Vol. C2012-001620. NACE International , 1. Marshall, P. W., & Copanoglu, C. C. (2009). Platform Life Extension By Inspection. The International Society of Offshore and Polar Engineers, 21-26 July 2009, (p. 1). Osaka, Japan. Moan, T. (2005). Reliability-based management of inspection, maintenance and repair of offshore structures. Structure and infrastructure engineering, Vol. 1, no. 1, 33-62.
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Nabavian, M., & Morshed, A. (2010). Extending Life of Fixed Offshore Installations by Integrity Management: A structural Overview. Abu Dhabi International Petroleum Exhibition and Conference, Vol SPE 138386. Abu Dhabi: Society of Petroleum Engineers. Nichols, N. W., Goh, T. K., & Bahar, H. (2006). Managing Structural Integrity for Aging Platform. SPE Project and Facilities Challenges Conference at METS, Vol. SPE 142858, 13-16 February 2011 (p. 1). Doha, Qatar: Society of Petroleum Engineers, Doha, Qatar. O'Connor, P. E., Bucknell, J. R., DeFranco, S. J., Westlake, H. S., & Puskar, F. J. (2005). Structural Integrity Management (SIM) of Offshore Facilities. Offshore Technology Conference, Vol. OTC 17545, 2-5 May, 2005, Houston, Texas, (p. 1). Houston, Texas. Perez Ramirez, P. A., Bouwer, U. I., & Haskins, C. (2013). Application of systems engineering to integrate ageing management into maintenance management of oil and gas. In P. A. Perez Ramirez, U. I. Bouwer, & C. Haskins, Systems Engineering (pp. 329-17). Piva, R., Latronico , M., Sartirana, S., Gabetta , G., & Nero, A. (2013). Managing structural integrity of offshore platforms: Looking back to drive the future. 6th International Petroleum Technology Conference, Vol. IPTC 16432 , (p. 1). Beijing, China. Stacey, A., Sharp, J. V., & Birkinshaw, M. (2008). Life Extension Issues for Ageing Offshore Installations. Estoril. STATOIL. (2013). Statoil's Oesberg C platform. Retrieved from STATOIL Web site: http://www.statoil.com/en/ouroperations/ncs/oseberg/pages/osebergc.as px Westlake, H. S., Puskar, F. J., O'Connor, P. E., & Bucknell, J. R. (2006). The Development of a Recommended Practice for Structural Integrity
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Management (SIM) of Fixed Offshore Platforms. Offshore Technology Conference, Vol. OTC 18332. Houston, Texas. Wintle, J., & Sharp, J. (2008). Requirements for life extension of ageing offshore production installations. Wright, I. (2011). Ageing and Life Extension of Offshore Oil and Gas Installations. Offshore Europe, Vol SPE 146225 .
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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
Very High
High
Moderate
Low
Nil
Level Relative Probability
1
¾
½
Level
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)
53
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.
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) ( 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 INSP
RELIABILITY OF TECHNIQUE
TECHNIQUE
RATIO
MPI
3
90%
CVI
2
90%
FMD
1
90 (10% for brace member, 80% for chord member)
GVI
0.75
60%
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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
consequence or repercussion rating is portrayed in the table below.
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of
Table A-4: Example of qualitative consequence rating (Animah, 2012) CONSEQUENCES Category
Low (1)
Medium (2)
High (3)
Safety:
When the likelihood of injuries is low.
When likelihood for lost time due to injuries is present.
When there is likelihood for serious injuries.
If failure effect on SCEs’ functionality is limited.
When SCEs are made non-functional.
When nonflammable medium is present.
When ignitable medium is under flash point.
When ignitable medium is over flashpoint.
When operational temperature and pressure are normal.
When temperatures and pressures of medium is extreme.
When temperatures and pressures of medium is very extreme.
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.
Functional failure
When likelihood for fire explosion is absent. Safety: Containment failure
Production
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 m inimal inspection.
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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)
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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.
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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 Assessment Issues
RELEVANT CODES, STANDARDS AND RECOMMENDED PRACTICES ISO 2394, General principles on reliability for structures, Chapter 8, Assessment of existing structures. ISO 13822, Basis for design of structures, assessment of
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