CRANFIELD UNIVERSITY

María Martínez Luengo

Multi-criteria Risk Identification and Maintenance Optimisation of

End of Life Scenarios for Offshore Wind Farms

School of Engineering

MSc in Renewable Energy Engineering

MSc Thesis

Academic Year: 2013 - 2014

Supervisor: Dr Athanasios Kolios

Industrial Supervisor: Dr Babak Eftekharnejad

Aug 2014

CRANFIELD UNIVERSITY

School of Engineering

MSc in Renewable Energy Engineering

Master of Science

Academic Year 2013 - 2014

María Martínez Luengo

Multi-criteria Risk Identification and Maintenance Optimisation of

End of Life Scenarios for Offshore Wind Farms

Supervisor: Dr Athanasios Kolios

Industrial Supervisor: Dr Babak Eftekharnejad

Aug 2014

This thesis is submitted in partial fulfilment of the requirements for

the degree of Master of Science

© Cranfield University 2014. All rights reserved. No part of this

publication may be reproduced without the written permission of the

copyright owner.

i

ABSTRACT

In 2007, the EU settled particular and challenging goals for all Member States

with the aim of reaching the common target of obtaining the 20% of their energy

consumption from renewables, by 2020. Nevertheless, the UK Government and

WFs owners have the duty of trying to make the already installed WFs not only

as much profitable as possible, but also more environmentally respectful.

Currently WTs are designed for a 20 years lifespan with the possibility of

operational extension. It becomes obvious that prolonging the efficient operation

and hence increasing the overall amount of produced electricity will significantly

increase return of investment (ROI) and decrease the overall cost of electricity

(LOC), considering that CAPEX will be distributed over a larger production

output. However, WFs life extension is not always viable. In order to carry it out,

an exhaustive risk identification was performed for all project’s phases in order

to combine it with an economical optimization of the maintenance plan. For the

cases in which life extension is not viable, other options so as repowering or

decommissioning have been explored.

The aim of this MSc project was to identify and assess activities that will make

the WTs life extension process possible. Therefore, a detailed Risk Register

throughout the service life stages and the O&M activities of OWTs was

performed and also maintenance activities were modeled and optimized,

identifying critical components and performing a cost analysis for risk

prioritization. To conclude, some alternatives for improving those maintenance

activities and therefore increasing profitability and reliability were suggested and

drivers to enhance WFs life extension and further investigation were settled.

Keywords:

Offshore Wind Turbines, Life Extension, Repowering, Maintenance, Risk

Identification

ii

iii

ACKNOWLEDGEMENTS

I would like to express the deepest appreciation to my supervisor Athanasios

Kolios for guiding me through this project, putting in a lot of effort no matter

what time of the day I needed help. All this personal and professional growth

would not have been possible without you.

Many thanks also go to Babak Eftekharnejad for his help in the project, with the

involvement of Bureau Veritas and NERC really appreciated. It allowed me far

greater exposure to the industry than would have been possible otherwise.

Also this project would not have been possible without the kindness and

supports of María Erans, Iris Gomez and Jesús Ortiz, among others. As

someone told me “We will never be completely at home again, because part of

our heart will always be somewhere else. That is the price you pay for the

richness of living and knowing people outside you own country”.

Finally, I also would like to thank my family; specially my parents and my

brother, for their unconditional support, advise and love during this year.

Without them and the unconditional support of Bernardo Beltrán I would not be

the person I am today and moreover, I could not have come to Cranfield to live

this awesome experience.

v

TABLE OF CONTENTS

ABSTRACT ......................................................................................................... i

ACKNOWLEDGEMENTS................................................................................... iii

LIST OF FIGURES ........................................................................................... viii

LIST OF TABLES ............................................................................................... ix

LIST OF EQUATIONS ........................................................................................ xi

LIST OF ABBREVIATIONS ............................................................................... xii

1 Introduction ...................................................................................................... 1

1.1 Background study ..................................................................................... 1

1.2 Aims and Objectives ................................................................................. 2

1.3 Structure of the work ................................................................................. 3

2 Literature Review ............................................................................................ 5

2.1 Introduction ............................................................................................... 5

2.2 Life Cycle Assessment .............................................................................. 6

2.3 Decommissioning...................................................................................... 8

2.3.1 Legislation ........................................................................................ 10

2.4 Repowering ............................................................................................. 11

2.5 Life Extension ......................................................................................... 13

2.6 Risk Identification and Assessment of end of life operations .................. 14

2.6.1 Risk Identification Tools and Techniques ......................................... 15

2.6.2 Risk Assessment .............................................................................. 16

2.6.3 FMEA and FMECA ........................................................................... 18

2.6.4 Conclusion ....................................................................................... 19

2.7 Maintenance of Offshore Wind Turbines ................................................. 20

2.7.1 Reliability-centred maintenance and Condition-based

maintenance .............................................................................................. 22

3 Service life and O&M risk identification: making the life extension process

possible ............................................................................................................ 25

3.1 Introduction ............................................................................................. 25

3.2 Service life risk identification ................................................................... 25

3.2.1 Introduction ...................................................................................... 25

3.2.2 Rotor ................................................................................................ 27

3.2.3 Blades .............................................................................................. 27

3.2.4 Gearbox ........................................................................................... 28

3.2.5 Pitch Control System ........................................................................ 29

3.2.6 Tower and Foundation ..................................................................... 29

3.2.7 Power electronics and electric controls ............................................ 30

3.2.8 Generator ......................................................................................... 30

3.3 Condition Monitoring Systems ................................................................ 35

3.3.1 Introduction ...................................................................................... 35

3.3.2 Gearbox and Bearing ....................................................................... 37

vi

3.3.3 Generators ....................................................................................... 38

3.3.4 Power Electronics and Electric Controls ........................................... 39

3.3.5 Rotors, Blades and Hydraulic Controls............................................. 39

3.4 O&M risk identification ............................................................................ 40

3.4.1 Introduction ...................................................................................... 40

3.4.2 Offshore logistics .............................................................................. 41

3.4.3 Onshore logistics .............................................................................. 42

3.4.4 Turbine maintenance........................................................................ 43

3.4.5 Export cable and grid connection ..................................................... 44

3.4.6 Array cable maintenance .................................................................. 45

3.4.7 Foundation maintenance .................................................................. 45

3.4.8 Back office, administration and operations ....................................... 46

4 A Cost Analysis Model for Risk Prioritization and Maintenance

Optimisation of Offshore WT Subsystems ........................................................ 51

4.1 Introduction ............................................................................................. 51

4.2 Baseline references ................................................................................ 52

4.2.1 Maintenance Categories .................................................................. 53

4.2.2 Equipment ........................................................................................ 59

4.3 Assumptions and estimations ................................................................. 60

4.4 Failure frequency study along the service life and life extension ............ 63

4.5 Maintenance activities Cost Analysis ...................................................... 64

4.6 Sensitivity Analysis ................................................................................. 71

4.6.1 Introduction ...................................................................................... 71

4.6.2 Methodology ..................................................................................... 71

5 Results and Discussion ................................................................................. 75

5.1 Failure frequency study ........................................................................... 75

5.1.1 Results ............................................................................................. 75

5.1.2 Conclusions and Recommendations ................................................ 83

5.2 Maintenance activities Cost Analysis ...................................................... 83

5.2.1 Results ............................................................................................. 83

5.2.2 Conclusions and Recommendations ................................................ 85

5.3 Sensitivity Analysis ................................................................................. 91

5.3.1 Introduction ...................................................................................... 91

5.3.2 Pitch System Sensitivity Analysis results, conclusions and

recommendations ...................................................................................... 91

5.3.3 Drive train Sensitivity Analysis results, conclusions and

recommendations ...................................................................................... 92

5.3.4 Yaw System Sensitivity Analysis results, conclusions and

recommendations ...................................................................................... 94

5.3.5 Generator Sensitivity Analysis results, conclusions and

recommendations ...................................................................................... 95

vii

5.3.6 Turbine Control and Protection System Analysis results,

conclusions and recommendations ........................................................... 97

5.4 Is Repowering a suitable option? .......................................................... 101

5.5 Further considerations .......................................................................... 102

6 Further Work ............................................................................................... 105

REFERENCES ............................................................................................... 109

APPENDICES ................................................................................................ 117

Appendix A Cost Analysis Model extended data and results ...................... 117

viii

LIST OF FIGURES

Figure 1 G90's life cycle ..................................................................................... 6

Figure 2 The recycling scenario: wind farm distribution over the end of life

options ......................................................................................................... 9

Figure 3 Schematic overview of different maintenance types........................... 20

Figure 4 Comparison of downtime to maintenance time per sub-assembly a) Downtime per sub-assembly; b) Maintenance time per sub-assembly .. 22

Figure 5 Bathtub curve of failure intensity showing effects on the curve of testing and maintenance............................................................................ 23

Figure 6 Internal construction of a typical WT assembly showing all the components. .............................................................................................. 26

Figure 7 Schematic flow of condition monitoring information ........................... 36

Figure 8 WT Power Curve ................................................................................ 53

Figure A-1 WT cost breakdown (5 MW Offshore WT).....................................117

Figure A-2 General data from the US WF.......................................................118

ix

LIST OF TABLES

Table 1 Technological Risk identification ......................................................... 34

Table 2 Summary of typical gearbox Condition Monitoring Techniques ........... 38

Table 3 O&M activities risk identification .......................................................... 49

Table 4 WT specifications ................................................................................ 52

Table 5 Equipment Description: associated costs and logistic times ................ 59

Table 6 WT Subsystems' failure frequency and cost ........................................ 61

Table 7 Maintenance Categories Description ................................................... 65

Table 8 Maintenance Categories Repair Costs ................................................ 68

Table 9 Maintenance Activities Cost Analysis .................................................. 69

Table 10 Pitch System's Sensitivity Analysis .................................................... 72

Table 11 Turbine Control & Protection System's Sensitivity Analysis .............. 73

Table 12 Servive Life Accumulated Failure Frequency for each Maintenance Category of every Subsystem .................................................................... 79

Table 13 Life Extension Accumulated Failure Frequency for each Maintenance Category of every Subsystem .................................................................... 82

Table 14 Critical subsystems' Maintenance Costs and Failure Frequency comparison ................................................................................................ 84

Table 15 Recommended changes on maintenance activities and their associated savings .................................................................................... 89

Table 16 Increase on Pitch System's Failure Frequencies ............................... 92

Table 17 Decrease on Pitch System's Failure Frequencies ............................. 92

Table 18 Increase on Drive Train's Failure Frequencies .................................. 93

Table 19 Decrease on Drive Train's Failure Frequencies ................................. 93

Table 20 Increase on Yaw System's Failure Frequencies ................................ 94

Table 21 Decrease on Yaw System's Failure Frequencies .............................. 94

Table 22 Increase on Generator System's Failure Frequencies ....................... 96

Table 23 Decrease on Generator System's Failure Frequencies ..................... 97

Table 24 Cost Sensitivity Analysis of the Turbine Control and Protection System .................................................................................................................. 99

x

Table A-1 Capital Cost structure of Offshore Wind Power Systems (2010) ... 118

Table A-2 Cost Analysis Table of results ........................................................ 125

Table A-3 Maintenance Categories including Large Parts Preventive Replacement ........................................................................................... 129

xi

LIST OF EQUATIONS

(2-1) .................................................................................................................. 19

(4-1) .................................................................................................................. 63

(4-2) .................................................................................................................. 63

(4-3) .................................................................................................................. 63

(4-4) .................................................................................................................. 66

(4-5) .................................................................................................................. 66

(4-6) .................................................................................................................. 66

(4-7) .................................................................................................................. 66

(4-8) .................................................................................................................. 67

(4-9) .................................................................................................................. 67

(4-10) ................................................................................................................ 67

xii

LIST OF ABBREVIATIONS

CAPEX Capital Expenditure

CBM Condition-based Maintenance

CM Condition Monitoring

DECC Department of Energy & Climate Change

DTI Department of Trade and Industry

ETA Event Tree Analysis

FMEA Failure Modes and Effects Analysis

FTA Fault Tree Analysis

HAZOP Hazard and Operability

HV High Voltage

H&S Health & Safety

IM Induction Machine

IT Information Technology

LCA Life Cycle Assessment

LOC Overall Cost of Electricity

M&A Measurements & Analysis

On&Off Onshore & Offshore

OPEX Operational Expenditures

OREIs Offshore Renewable Energy Installations

OW Offshore Wind

OWF Offshore Wind Farm

OWT Offshore Wind Turbine

O&M Operations & Maintenance

PPA Power Purchase Agreement

PRA Probabilistic Risk Analysis

PrHA Preliminary Hazard

RCM Reliability-centred Maintenance

REZ Renewable Energy Zone

ROI Return of Investment

ROVs Remotely Operated Vehicles

RPN Risk Priority Number

xiii

SAP Senior Authorised Person

SCADA Supervisory Control and Data Acquisition

SCIM Squirrel Cage Induction Machine

SWOT Strengths, Weaknesses, Opportunities and Threats

WF Wind Farm

WT Wind Turbine

1

1 Introduction

1.1 Background study

The depletion of fossil fuels reservoirs, its tremendous price oscillations, the

vast impact those fuels have on the environment and their high participation into

climate change have obligated the European Union to turn towards alternative

forms of sustainable energy [1]. In 2007, the European Union settled particular

and challenging goals for all Member States [2] with the aim of reaching the

common target of obtaining the 20% of their energy consumption from

renewable energies, by 2020. However a lower percentage of 15% was

established as the UK’s restriction, with the additional requirement of lowering

its CO2 emissions to a minimum of 26% by 2020 and 60% by 2050 [3].

In order to ensure these targets achievement, the economical optimization of

this industry is crucial. This optimization encompasses a huge amount of

activities as [4]: lowering the construction and insurance costs, increasing the

service life and providing the life extension option by a good maintenance and

risk management and optimising the O&M activities.

The UK’s OW Program started in 2001 with “Round 1”, which is the smallest

one and had a capacity around 1.5 GWe. However, just 1GWe was built. The

second round was quite bigger and included 7.2 GW of capacity. The first set of

“Round 2” was connected to the grid and started being in operation in the

summer of 2010 [5]. Six years after the start of “Round 1”, the Government of

the United Kingdom proclaimed the new “Round 3” project which raised the

amount of issue of leases for almost 32GWe of OWF [6]. Right after that,

another six and a half GWe worth of leases were issued for development of

OWF in Scottish waters. Besides Rounds one and two extensions were also

approved [5].

The approximately 50 GW of electricity generated by the three different rounds

is expected to generate around the 45% of the total demand of the whole United

Kingdom, using for its calculation the Capacity factor of 2008 estimated by

2

DECC [7] (a 35%) and the 336 thousand GWh of United Kingdom’s expected

electricity demand in 2020, estimated also by DECC [8]. Moreover, if both

On&Off installations are taken into account, it can be assumed that more than

the half of the total electricity demand would be covered just by Wind Energy

[6]. Nevertheless, even those targets are part of a really ambitious plan, the UK

Government and WFs owners have the duty of trying to make the already

installed WFs not only as much profitable as possible, but also more

environmentally respectful.

Currently WTs are designed for an assumed service life of 20 years with the

possibility of operational extension. It becomes obvious that prolonging the

efficient operation and hence increasing the overall amount of produced

electricity will significantly increase return of investment (ROI) and decrease the

overall cost of electricity (LOC), considering that CAPEX will be distributed over

a larger production output. However, even the best option will be those WFs life

extension, it is not always viable. In order to be able to carry it out, an

exhaustive risk identification must be done for all project’s phases and a

combination of those risk management with an appropriate O&M plan must be

performed. If finally life extension is not viable, other options so as repowering

or decommissioning must be explored. For these reasons, further research

focusing on OWFs service life extension becomes essential.

1.2 Aims and Objectives

The aim of this MSc project is to identify and assess activities that will make the

WTs life extension process possible. The main objectives of this project are:

I. Perform a literature review on WFs end of life scenarios and a deep

study in risk identification and assessment of end of life operations and

OWT maintenance.

II. Elaborate a detailed Risk Register throughout the service life stages and

the O&M activities of OWTs.

III. Carry out a deep research in the most up to date CM Systems and

assess which components failures could be diagnosed.

3

IV. Model OWTs maintenance activities. Identify the critical components and

perform a cost analysis for the risk prioritization.

V. Prioritize critical components risks among their maintenance categories

and evaluate their impact over the system.

VI. Suggest improving ways of maintenance activities and therefore WT

profitability and reliability.

VII. Come up with further work to keep investigating this subject.

1.3 Structure of the work

This work has been divided in 6 chapters. Taking into account that the first one

is the present chapter, on the second one, an extensive literature review about

WFs’ end of life scenarios and risk identification and assessment techniques of

end of life operations and OWT maintenance, was developed.

After this research, OWTs service life stages and O&M activities risks were

identified and listed on a detailed Risk Register. Besides, a deep research

throughout all components CM systems was performed. These activities can be

seen on Chapter 3.

Chapter number 4 records the OWTs economical modeling of maintenance

activities; identifying critical components and performing both, a cost analysis

for the risk prioritization and a sensitivity analysis for assessing the impact that

critical components failures cause on the system. Moreover Chapter 5 shows

Chapter 4’s results and suggests improving ways of maintenance activities and

therefore WT profitability and reliability. Besides, based on Chapter 3, it

considers other options to enhance these two qualities.

Finally Chapter number 6 suggests the further work that could be carried out in

case someone wants to focus a PhD on this subject.

5

2 Literature Review

2.1 Introduction

The United Kingdom is subject to a legally binding European aim to acquire the

15% of its energy consumption (heat, electricity and transport) from renewable

technologies by 2020 [9]. Furthermore the Climate Change Act [10] imposes a

legally binding target, to reduce carbon dioxide emissions to 20% of 1990 levels

by 2050. Therefore, renewables have rapidly become crucial for these targets

achievement [11].

For the UK’s achievement of the 2020 target, a moderate increase of the

development speed is necessary. However, as it is pointed out by Emma

Gibson in [12], this objective is plenty of intricate hurdles as could be: the

economy of the project, technological limitations, supply chain capacity, social

and environmental impacts, among others.

However, there are another two procedures that will increase the possibilities of

these targets achievement, which are the WF life extension and repowering. As

it is explained in following sections, WTs life extension is carried out when the

WT is either in good conditions or just few replacements and maintenance are

enough to enable it to keep working for an extra period of time, which will

reduce considerably the environmental impact produced by the turbine, due to

the fact that those impacts are amortized in a longer period of time.

Repowering represents the procedure of changing an existing WT for another

one newer that either has a greater rated power or higher efficiency, resulting in

a considerable increase of the total generated electricity [13].

6

2.2 Life Cycle Assessment

Life Cycle Assessment (LCA), also called “cradle to grave” study, is a method

used to evaluate the environmental effects produced within the different phases

of a product's life, which implies that environmental impacts are assessed from

the raw materials extraction and across their processing, manufacture,

distribution, use, repair and maintenance, and decommissioning or end of life,

which also includes the recycling or obliteration of all of those materials.

The figure below (Figure 1) owes to an study performed by GAMESA [14] and

summarizes the entire life cycle of the G90 (2.0 MW) including all the stages

from extraction of all the necessary raw materials to their waste recycling or

final disposal, as it is specified on the standards that have been followed to

perform the studies. Those standards are:

ISO 14040:2006. Environmental management. Life cycle assessment.

Principles and framework.

ISO 14044:2006. Environmental management. Life cycle assessment.

Requirements and guidelines.

Figure 1 G90's life cycle

Source: [14]

7

The different stages showed on the figure above can be classified into seven

phases which are: Sourcing of Raw materials and Components, Manufacturing,

Distribution, Installation, Operation, Maintenance, Dismantling (End of Life).

However, for the better understanding of the process, these phases are usually

grouped into four: Production, Assembly, O&M and End of Life.

As the title of this project expresses, it concerns about the End of Life of an

OWF so, the fact that the End of Life phase takes into account all environmental

impacts since the wind farm is decommissioned until all materials are reused,

recycled, rehabilitated or ultimately eliminated, needs to be clarified. It also

takes into account the impact associated in transportation of all turbine

components and the ones related with the final treatment made to each

component.

However, there is an extremely simple way to reduce the overall impact that a

WF produces; it consists on increasing the time that this WF is in operation (life

extension) due to the fact that it emits no CO2 during these phase. Therefore, if

the energy necessary employed to build, operate and disassemble a normal WT

is retrieved within 9 months of operation for a lifespan of 20 years [15], by

increasing the Operation and Maintenance period (O&M) the turbine will still

producing green energy for longer, which is traduced in, for the one hand,

higher benefits and for the other hand, less environmental impact. For this

reason the concept “Life extension”, which will be discussed later, constitutes a

good choice before performing the “repowering” or the decommissioning of a

WF.

[16] As it has been specified before, a WT is designed to be in the O&M phase

for twenty years. This is called lifespan. Even designing and building some of

the components for longer operational life would be easy, building a WT for a

longer life span would be very expensive and not worthy. By agreeing on a 20

years lifespan, an economic compromise is arranged in order to facilitate the

engineers who improve WTs subsystems, the design targets.

8

The design service life of a subsystem compared to its real lifespan implies that

a WT may still working for longer or lower service life than the one planned at

the beginning of the project. The extra years that the WT will be able to still

producing energy depend on the structural strength and build quality of every

subsystem, the quality of the subsystems assembly and the impact that the

environmental conditions produce on the system. Those environmental

conditions are not only referred to the wind properties like the turbulence level

at the emplacement, but also to the average humidity, the air density and their

variation or even also the seismic behavior of the emplacement. An OWT may

have longer service life just because, for example, having lower turbulence

level, due to the absence of obstacles sea has.

2.3 Decommissioning

The decommissioning of a WF constitutes the final stage of a project. The main

objective of this stage is returning the seabed to its original conditions as far as

practicable [17].

On the decommissioning phase of a WF, all WT elements have to be

transferred by vessels and trucks from the offshore emplacement to the

onshore one and finally, to their treatment location. [18] If a WT needs to be

totally dismantled, firstly the tower and all blades will be disassembled and

hoisted down by crane, for its posterior elements disjoint and size reduction into

small pieces suitable for scrap [19]. Almost every WT material will be

salvageable. Usually the base is left in the same place and covered by gravel

and peat tracks used for maintenance vehicles and gates in fences will be

removed, in case of an onshore emplacement. Moreover, the qualification and

crew for the decommissioning activities is used to be comparable to those of the

commissioning stage.

Due to the fact that WTs bases are made of reinforced concrete which is a

toxin-free material, they do not represent a hazard to the environment and can

be just covered with no environmental remediation required. On the contrary,

lubricants are required in WT operations, however on Gearboxes are designed

9

to decrease maintenance costs. Therefore no soil remediation is needed.

Tracks are generally gravel and can be simply covered with loam and grass

seed, disappearing completely within a couple of years.

For the recycling scenario, the detailed disposal flow is shown in Figure 2. The

recycling scenario explains the way that the OWF is distributed over the end-of-

life options. Firstly, the OWF is disassembled and separated into elements by

assuming identical energy consumption that on the commissioning phase.

Then, waste treatment is performed depending on the kind of material used.

Waste treatments are divided in: recycling, landfilling, and incineration.

Figure 2: The recycling scenario: wind farm distribution over the end of life

options

Decommissioning and recycling implications and costs must be clear to

municipalities, small land owners and WT developers; especially which party is

liable for them.

Even few years ago decommissioning was the dominant scenario, nowadays

companies are trying to keep operating WFs as long as it is possible (life

extension), provided that it is the worthiest solution. Thus the WF can be re-

10

powered or decommissioned with the aim to build another one more powerful;

due to the fact that an old well positioned WF remains well positioned. Most of

times, it is more profitable repowering an already used emplacement than

establishing a new one.

[17] Previous the first WF stage building, the developer must submit to the

relevant regulatory authority a decommissioning method statement, including

the scope, disassembling techniques and H&S and environmental safeguarding

measures; updating it before the decommission starts. Besides, the WF

Operator may still having environmental commitments after the

decommissioning due to any not previously solved latent inconvenient. Within

next paragraphs, the legislation created in order to regulate decommissioning

activities, is described.

2.3.1 Legislation

Decommissioning of Offshore Renewable Energy Installations (OREIs) in the

United Kingdom is regulated under Chapter 3 of Part 2 of the Energy Act 2004

[20] which, as far as the Renewable Energy Zone is concerned, implements the

UK’s obligations on decommissioning under the United Nations Convention on

the Law of the Sea [21]. The Act enables the Secretary of State to require

developers of OREIs to submit a costed decommissioning programme to the

DTI (Department of Trade and Industry), setting out the measures to be taken to

decommission the installations and estimating the potential costs and timing.

This programme must be executed by the liable entity whenever

decommissioning is necessary.

The Energy Act 2004 [20] defines the ‘Renewable Energy Zone’ (REZ) as an

area beyond territorial waters, in principle out to 200 nautical miles (370 Km)

from the baselines (usually the low water mark). The scheme also applies to

waters around Great Britain further inshore, from the mean low water mark to

the seaward boundary of the territorial sea. The Crown Estate has the right to

provide leases or licenses for the installation of renewable energy installations

[21]. The DTI has identified three strategic areas for OW development: the

11

Greater Wash, the Thames Estuary and the North West (Liverpool Bay). Future

rounds of OWF developments are currently planned for these three areas.

The Energy Act 2004 [20] refers to the use of financial securities aimed at

guaranteeing delivery of the decommissioning programme. The requirement for

financial securities is discretionary. Submitted decommissioning programmes

are subject to periodic review “from time to time” and modification to the

programme is subject to the approval of the Secretary of State. The review

includes the suitability of any current financial securities.

Under the Energy Act 2004 [20], if the liable entity defaults in carrying out the

decommissioning programme the Government, as a last resort, may carry it out

itself and where possible will recover the cost incurred from the liable entity.

Criminal penalties are available if a liable entity fails to carry out the

decommissioning programme.

2.4 Repowering

A WF’s repowering is the procedure of reestablishing existing WTs with new

ones that either have a larger rate power or higher efficiency, increasing the

total generated electricity. Although this activity carries, both, social and private

benefits, there are also some hurdles that can be managed with public support

[13].

[17] In the last years of a WF’s operational life, the owner might decide

repowering is a profitable option and buy new WTs. This decision would have

been based on the WF’s profitability and the benefits ratio that repowering will

present against the WF full decommissioning and project components recycling.

Every WT present a specific design lifespan based on every subsystem’s life

expectations due to the fact that, depending on the subsystem, higher or lower

wear and tear will be expected and the combination of all of them and the

subsystems’ maintenance will state the WT’s lifespan. For instance, generally a

moving part wears out faster than a static part and an exposed component

faster than its shielded alternative. Therefore two of the subsystems that

present higher wear are blades and the gearbox [16].

12

One possibility would be reusing some infrastructure from the WF to reduce the

capital cost the second one. For example, most of the original subsea cables

might be reused, along with the existing grid connection. However, if the WT

capacity has been increased, the grid connection may have to be changed.

In order to repower, a distinct financial close process will have to be

undertaken, leading to a second construction phase and O&M phase, with all

that these phases entail [17]. Most of the times, WT are erected in

emplacements highly interesting in replacing a WT that has exceeded its

lifespan with another one with same or better qualities. Some examples of this

kind of projects are most of the WF in California, Nevada, Holland and Denmark

due to the fact that there is no reason to believe that a good WF emplacement

will become not productive. Therefore, those emplacements will still being

profitable whilst electricity is required [22].

General WT experience in Denmark is that most of the two thousand turbines

built by 2008 had a useful service life of 15.9 years before the repowering

option became profitable. [23] On the contrary, there are comparable studies

that find profitable start changing turbines after a useful service life of 17 years,

instead of the 20 that a WT is supposed to last in good conditions. Moreover

refurbishing WTs secondary markets have recently emerged making some WFs

immediately profitable [24]. Besides, other countries like Germany and USA

have started replacing 1st and 2nd generation WTs changing them to other ones

with considerably higher rate power and reducing the quantity of WTs installed

in some regions [25].

The United Kingdom has recently given consent to RWE Npower Renewables

to perform the repowering of one of the first Onshore WF. The project that, on

the one hand, will consist on the reduction of the quantity of WTs, on the other

hand will imply multiplying the power generated by two, which means that the

WF built in 1993 and made of twenty WTs is going to be transformed into a WF

composed by seven WTs with a capacity of 17.5 MW that constitutes more than

twice the actual power generated each year [26].

13

2.5 Life Extension

In some circumstances, when a WT arrives to its final years of service life it

might be worthy refitting the WT by increasing its service life rather than

repowering it. A big inspection usually will imply the replacement of most of the

internal subsystems and the blades [16]. Usually it is common the tower stills

conserving itself well and can be used safely for some more years. Besides, an

important advantage is that the common spares costs (set of blades, the

Gearbox and the Generator) are between the 15% and the 20% of a new WT

cost. However it will depend on each case, therefore an intensive analysis has

to be performed in order to determine the suitability and safety of the existing

subsystems.

In another study, made in the Imperial College Business School of London a

detailed research and a posterior analysis of the United Kingdom WFs were

performed using local Wind Speeds taken from NASA. On its results it can be

appreciated that most WT will last about 25 years before they need to be

upgraded [15]. Researchers also discovered that the first set of UK's WTs,

erected in the 90s, after their whole lifespan, were still being profitable due to

the fact that their production was about 3/4 of the starting one and almost the

double of the quantity previously claimed. Besides it was estimated that those

turbines might still operating for another 5 years, being their performance as

good as the one of gas turbines used in Power Plants.

An analysis of different life extension scenarios was also performed by

GAMESA [14] to estimate the viability of the operational life extension and the

impact variation within the LCA. This analysis was carried out for life extension

periods of five and ten years, for a lifespan of twenty years.

On the study, the viability and the impacts on the LCA, of the useful life

extension was perfectly estimated by taking into account variations in: energy

production, additional maintenance, both for additional supplies such as trips to

park maintenance staff, end of life management of these supplies, as well as

the need to transport them to the site itself, manager, etc...

14

Results show a noticeable decrease in the overall impact of the life cycle in both

cases. For the case of 5 year life extension, the overall impact was reduced

near a 20% while if the extension was for 10 years, the decrease would be

more than the 30%. These results are logical, as impacts are amortized over

more years.

As it has been pointed out before, in order to achieve the life extension of a WF,

a thorough risk identification and assessment have to be performed to conclude

if the extension of the turbine useful life is possible or the repowering will

constitute a better option. During the next section, different risk identification

and assessment techniques, suitable to this aim, are going to be exposed.

2.6 Risk Identification and Assessment of end of life operations

Risk identification is a subjective procedure, strongly based on experience,

which main aim is to determine the risks that may occur during the whole life of

the project and document those risks characteristics. This is a continuous

procedure due to the fact that new risks may arise as the project progresses.

Involvement of different parties in the identification procedure can mitigate the

danger of omitting significant sources of risk.

Usually this study is carried out by the project team, the risk management team,

company experts and also from the outside, other project managers,

stakeholders, etc. However, not all of participants would be present in every

stage of the project.

Published information, such as Commercial Databases, academic reports,

benchmarking and other kind of studies that might be accessible, are some of

the most important inputs to the risk identification. Another one is the recorded

historical information that the organizations that are taking part on the current

project had previously produced like for example Final Project Reports or Risk

Response Plans. Some lessons based on previous experiences might been

included, describing different problems, their sources and also their resolutions.

15

Besides, the risk identification process needs a deep understanding of the

project's mission, scope, owner’s objectives, sponsors and stakeholders.

To perform an effective risk identification some documents elaborated during

the project planning must be examined. Those documents which constitute a

support to the risk identification are among others: Project Charter, Project

Scope, work breakdown structure, Project Schedule, Cost Estimates, Resource

Plan, Procurement Plan, Assumptions List, Constraints List, etc.

2.6.1 Risk Identification Tools and Techniques

Apart from the revision of project documents to identify the risks, checklists of

risks can be developed by exhaustive information collection from past similar

activities as these are quickly threats identification methods for new projects.

However, the possibility of other risks has always to be taken into account.

There is another good risk identification technique that consists on analyse the

assumptions made in the project plan. This technique evaluates the

assumptions’ accuracy. It identifies both project’s inaccuracy and inconsistency

risks and assumptions incompleteness. Other possibility is constituted by the

employment of different information-gathering techniques. Some of the most

important are:

Brainstorming: it is one of the most commonly used Risk Identification

techniques. Its aim is to gather an exhaustive risk register for its posterior

addressing in the Risk Analysis Process.

To carrying it out, an appointment is scheduled with multidisciplinary

experts groups that identify risks, under a leader’s guidance. The

brainstorming process progresses neither with intrusion nor

discrimination or examination of others’ ideas nor with regard to

individuals’ status in the organization. Risks will later be divided by

different types of risks and their definitions will be clarified. This method

is more effective if participants prepare in advance and the facilitator

develops some risks in advance.

16

Delphi technique: it is a method that helps reaching unanimity of experts

on a specific issue as Risk Ranking while preserving anonymity by asking

opinions about the topic [33]. This method assists bias reduction at the

same time that particular experts’ influences on the process are

minimized.

To carry it out, the chair gives a questionnaire or interview to the

participants to provide ideas about the project risks. Once the answers

have been submitted, a classification into risk categories is performed.

Then, those risks are distributed to the people that are taking part on the

study and commented. Most of the times, several rounds are necessary in

order to reach unanimity.

Interviewing: some questionnaires are carried out to experts and people

of the sector to provide a risk identification. The interviewees identify risks

on the project based on their experience, the project information, and any

other sources that they find useful.

Root Cause Analysis

Strengths, Weaknesses, Opportunities and Threats (SWOT) Analysis:

Provides the project assessment from these four different points of view

to extend the amplitude of the risks that have been taken into

consideration.

Lastly, there is another important group, the diagramming techniques, which are

formed by Cause & Effect Diagrams, Influence Diagrams and System or

Process Flow Charts.

2.6.2 Risk Assessment

Next step right after the risk identification process is the assessment of all the

identified risks to estimate its likelihood, consequences and the level of risk that

it represents.

17

Due to the fact that the amount of risks identified usually is considerably

superior to the Project Team’s time capacity; in order to evaluate and elaborate

a mitigation plan, a prioritization process is carried out to help those risks

management; especially of these risks that have both a high impact and a high

probability of occurrence [33].

Quantitative assessments and qualitative assessments [30] are the main

types of risk analysis techniques. The major benefit qualitative impact analysis

has, is the risk prioritization that is performed for the posterior critical impacts

identification and vulnerabilities refinement. However, no quantifiable

measurements of the magnitude of the impacts are provided by this analysis,

which has repercussions on the difficulty in performing a cost-benefit analysis of

any recommended control.

The major benefit quantitative impact analysis has, is the availability of a

quantification of impact’s magnitude, making the cost-benefit analysis of any

control easier. However, this type of analysis entails a disadvantage, which is

that the sense of the analysis might be ambiguous due to inconsistence of the

numerical ranges in which the measurements were expressed, demanding a

qualitative interpretation of those results. Some of the most important qualitative

and quantitative methods are [33]:

Hazard and Operability Study (HAZOP): This method identifies from

system’s variations the phenomena that might drive the system to

undesirable consequences. Thus recommendations are made to this

consequences remediation.

Preliminary Hazard Analysis (PrHA): It is an inductive modeling

approach, which identifies and prioritizes hazards with the potential to

lead into undesirable consequences early in the life of a system. It

determines recommended actions to reduce the frequency and/or

consequences of the prioritized hazards.

18

Failure Modes and Effects Analysis (FMEA): It is an inductive modeling

approach that will be explained better lately, which identifies the

components failure modes and their impacts on the surrounding

components and the system.

Fault Tree Analysis (FTA): It is a deductive modeling approach that

identifies combinations of equipment failures and human errors that can

result in an accident.

Event Tree Analysis (ETA): It is an inductive modeling approach that is

used to assess and separate various sequences of events, both failures

and successes that can lead to an accident.

Probabilistic Risk Analysis (PRA): This methodology is a quantitative risk

assessment technique that was developed by the nuclear engineering

community for risk assessment to perform a comprehensive process

using a combination of risk assessment methods.

2.6.3 FMEA and FMECA

Failure Modes and Effects Analysis (FMEA) or Failure Modes and Effects and

Criticality Analysis (FMECA) [32], as their own name indicate, are powerful

system design tools which provide to an experts team, the possibility of

comparing alternative machine configurations to see which one is the most

profitable and represents lower levels of risk. For these reasons are considered

as very useful for a technology that is changing or increasing in rating, as WTs

configurations are.

Since FMEA is used by various industries, including automotive, aeronautical,

military, nuclear and electro-technical, specific standards have been developed

for its application. A typical standard will outline Severity, Occurrence and

Detection rating scales as well as examples of an FMEA spreadsheet layout.

The rating scales and the layout of the data can differ between standards, but

the processes and definitions remain similar, for example:

19

BS EN 60812:2006: the British Standard. It is the official English

language version of EN 60812:2006. [34]

SAE J 1739 was developed as an automotive design tool and Ford has

used it as a Design Review process.

SMC Regulation 800-31 was developed for aerospace.

IEC 60812:2006 [35] is a general standard.

MIL-STD-1629A (1980) [36] drafted by the US Department of Defense.

The FMEA process allocates numerical values for every risk and its cause to

three criteria: failure’s severity, probability of occurrence and difficulty of

detection. Those criteria are joined by its multiplication in the called Risk Priority

Number (RPN), which is employed for the system’s risk analysis and ranking.

The higher the risk is, the higher the RPN value is.

(2-1)

2.6.4 Conclusion

Along the previous sections the most used risk identification and assessment

techniques have been introduced. These techniques are employed thorough all

the project stages, concretely from the planning phase to the end of life.

It seems obvious that different types of risk will constitute the priorities at each

stage of the process. For example, while at the beginning of a project, during

the planning and commissioning stages, the ROI, unexpected commissioning

costs and the environmental impacts constitute the priorities in terms of risks, at

the end of life of a WT and even more if its life extension is going to be carried

out, technological and financial risks like components replacement, LOC and

O&M costs are the main concerns.

Therefore, in order to be able to extend our WT life, good maintenance needs to

be carried out. However, it can easily leads into undesirable high O&M costs.

20

For that reason, a compromise between a good maintenance and its costs has

to be reached.

2.7 Maintenance of Offshore Wind Turbines

Typically, there are two different maintenance approaches: preventive and

corrective. Preventive maintenance is predictable and scheduled, whereas

corrective maintenance (repairing things when they go wrong) is unexpected,

unscheduled and often expensive [38].

For that reason, corrective maintenance has been tried to be reduced as much

as possible by performing comprehensive preventive maintenance plans

(scrupulously carried out) and by using CM to identify incipient faults early so

that appropriate planned action can be taken. Equally important though, is to

target reliability and build this in at every stage of the development and

engineering cycle.

Figure 3: Schematic overview of different maintenance types

Source: [30]

21

There are other important issues related to large OWTs accessibility and

maintenance. The availability of appropriate vessels and cranes usually

represents one of these issues, limiting operational conditions and the need for

suitable weather windows. Other factors include the availability of trained

personnel and, overall, the lack of an established O&M infrastructure [38].

WT maintenance technicians require a special blend of technological skills and

knowledge, including: organization and initiative; WT product knowledge;

mechanical, electrical, control and software expertise; appropriate H&S working

practices; survival abilities in the offshore environment; etc [32].

The exigencies of weather offshore and of the difficulties of access in bad

weather mean that many preventive maintenance activities cannot be

performed when scheduled. This fact induces the creation of a certain degree of

planning and preventive action, which is creating a shift in OW O&M

management towards a maintenance and asset management strategy.

Spares holdings have generally been the responsibility of the Original

Equipment Manufacturers, but as WF sizes have grown, the importance of

having key spare sub-assemblies available for rapid change-out has become an

important issue and this is of increasing concern offshore, where the window for

repair, due to weather, logistic and other operational constraints, may be short.

Spares are usually divided in:

Major spares: Blades, Gearbox, Generator, Hydraulic Power Pack,

Converter-Inverter modules, Pitch and Yaw Motor Mechanisms.

Consumable spares: Lamps, buttons and control relays, Pump motors,

Filters, Grease packs, Lubricating Oil Packs.

22

2.7.1 Reliability-centred maintenance and Condition-based

maintenance

Reliability-centred maintenance (RCM) is made when maintenance activities

are based on WT sub-assembly failure rates and downtimes. Therefore, from

Figure 4, maintenance time on the Gearbox would be arranged to be 22% of

total, bearing in mind the downtime Gearbox causes. This distribution of

maintenance will vary with time, depending on the performance of wind turbines

and their sub-assemblies.

Figure 4: Comparison of downtime to maintenance time per sub-assembly

a) Downtime per sub-assembly; b) Maintenance time per sub-assembly

However, such an approach may be misguided unless the maintenance activity

reduces failure subassembly rates and downtimes. In order to determine it,

subassemblies’ history and performance must be clearly understood.

Thus, it can be achieved by monitoring the performance of the WT using

methods like those described in [39], that is, condition-based maintenance

(CBM). WTs have exceptionally good monitoring cover because of their

unmanned remote robotic operation but very few operators are making use of

the monitoring information to manage their maintenance because of the volume

and complexity of the data. That must change offshore. The data must be

simplified and presented in a coordinated, comprehensible way, hence the need

for a data management system. Besides, in [32] the necessity of standardizing

23

the reliability data collection methods for the wind industry, as it has been done

for the oil and gas industry [42], is pointed out.

The data management system must then be used to drive RCM and CBM to

raise availability and lower cost of energy. Both RCM and CBM drive the need

for an OWF Knowledge Management System [40].

RCM and CBM address the ongoing operation of the WF but they cannot, on

their own, secure the through life reliable performance of the WF without longer

term management of the asset [41]. The high capital cost of OW demands a

rigorous operational regime that generates energy at an adequate price that

recovers the cost of the investment. But once payback is achieved, the life of

the asset will determine its long term profitability.

These longer term benefits can only be secured by long term management of

the asset by controlling the later part of the bathtub curve (Figure 5) where wear

out of sub - assemblies is controlled by their planned change out.

Figure 5: Bathtub curve of failure intensity showing effects on the curve of

testing and maintenance

25

3 Service life and O&M risk identification: making the

life extension process possible

3.1 Introduction

From the beginning of an OW project, during the planning stage and thorough

its early life, an exhaustive risk identification is performed with special emphasis

on all technological and environmental risks that can be experimented by a WT.

This process is executed in order to elaborate a good maintenance plan that

allow the implicated parts (owners, manufacturing companies, third parties, etc)

to keep the turbine in good conditions, not only searching the economical

viability of the project, but also providing the possibility of life extension.

In this chapter, the main technological risks that might occur along the service

of the WT have been identified. Thus, the Condition Monitoring Systems (CM)

suitable for managing those risks have been introduced and explained.

To conclude the chapter, a risk identification of the Operations and Maintenance

(O&M) process has been carried out in order to figure it out the phenomena that

could jeopardize the life extension objective. It is believed that both risk

identifications will constitute the base of work for future life extension processes,

making it a reachable reality.

3.2 Service life risk identification

3.2.1 Introduction

As it has been stated before, a realistic and a detailed risk identification of the

main problems that each turbine subsystem may experiment along its service

life, must be performed at the beginning of a project for the adequate

maintenance management.

Along this section the components that compromise the WT performance at a

higher rate have been identified as: rotor (hub), blades, generator, pitch control,

gearbox (the proper gearbox and the yaw system gearbox), tower and

foundation, power electronics and electric controls.

26

Those components were assessed individually for a correct risk identification. It

is expected that the majority of the risks identified below could be controlled at a

real time with one or even more of the CM techniques that have been explained

in the next section, as these tools represent a considerably system’s reliability

improvement. However, this risk identification must be taken as the compilation

of the most important and, at the same time, most studied WT risks, assuming

the existence of more potential risks that might not have been included in this

report.

Figure 6 has been included for the better location of the components analysed

below and their risks.

Figure 6 Internal construction of a typical WT assembly showing all the

components.

Source: [80]

27

3.2.2 Rotor

Almost twenty years ago, P. Caselitz and two colleagues carried out the

analysis of rotor anomalies [69], where the most common were stated as

aerodynamic asymmetry and yaw misalignment [69, 70]. Thus, some years

before, in 2001, an investigation of the bearing’s behaviour due to not uniform

airgap and slip-speed was carried out by E. Brusa et al [103].

In 2009, on an investigation about drive train fault diagnosis of a synchronous

generator WT [84], the torsional oscillation and the deviation of the

torque/speed ratio were studied. It can be appreciated that the information

extracted from this study provides the possibility of more rotor faults detection,

however there are other documents suitable also to this aim, as the one done

by F. Spinato, and P. J. Tavner called: “Condition monitoring of generators and

other subassemblies in wind turbine drive trains” [104], where, for example, the

mass imbalance fault was identified and its consequences were taken into

account.

Some other major rotor faults are subjected to creep and corrosion fatigue [68],

which might have catastrophic consequences due to wrong maintenance and

inspection of the cracks and delaminations of the composite blades produced

by the fatigue. Rotor imbalance and aerodynamic asymmetry might happen due

to ice, dirt and moisture accumulation. However damage accumulation into the

rotor blades can also be the root cause of these faults.

Other common rotor failures are hub’s spinng on shaft [68] or shaft

misalignments [71], among others.

3.2.3 Blades

WT blades are vital components which must be monitored for ensuring the

correct operation performance. As it has been just commented, blades can

suffer delamination of its composite layer and cracks of different depths due to

rotor’s creep and corrosion fatigue [71, 72]. Besides, the WT can experiment a

decrease of the energy captured (efficiency loss) produced when the blade

surface roughness increases [74]. This phenomenon and the surface wear [73]

28

are produced by the erosion, icing, insects etc, the WT is subjected to. Another

potential failure is the blades flapwise fatigue damage [77], which can be

controlled or reduced by the pitch control system, as it is exposed by J. Arrigan

et al, on their study called “Control of flapwise vibrations in wind turbine blades

using semi-active tuned mass dampers”.

Unfortunately, WT blades undergo different fault and damage types that are not

suitable for monitoring employing WT generator terminals. Blades are especially

laid open to lightning strikes which are random natural phenomena. To prevent

damage, as it cannot be monitored, Lightning Protection Systems are used [79].

However, complete protection is not ensured.

Other common blade faults are: high vibrations [75], unsteady performance [79],

corrosion and unsteady blades airloads [78], which at the worst scenario can

produce blade fracture [68].

3.2.4 Gearbox

Gearbox is the component that suffers more faults among all subsystems of the

WT drive-train [71, 85]. On a study called “The gearbox reliability”, written by

McNiff [86], gear tooth damage and bearing failure are qualified as usual

failures. Furthermore, this last failure is also characterized as the leading failure

of WT gearboxes and therefore on WT drive-trains.

This study also points out [86] that “among all bearings in a planetary gearbox,

the planet bearings, the intermediate shaft-locating bearings and high-speed

locating bearings tend to fail at the fastest rate, while the planet carrier

bearings, hollow shaft bearings and non-locating bearings are most unlikely to

fail”. Another important failure is the shaft-gearbox decoupling, which is

consider catastrophic [68], while pitting, cracking, scratching and other faults

are not considered that critical [86], as they can be early detected with gearbox

diagnosis and CM methods like Acoustic Emission (AE). Moreover, P. J. Tavner

et al. [84] wrote a study related to the WT drive-train diagnosis, where the

electrical analysis was assessed for mechanical defects and the diagnosis of

gear eccentricity was investigated.

29

Lubrication constitutes a very important part of the WT rotating components and

particularly of the gearbox subsystem [88]. The variation of oil properties such

as viscosity, water content, particle count, and presence of additives commonly

imply potential faults [89, 90].

3.2.5 Pitch Control System

Pitch control system is a crucial element for the WT operation, due to the fact

that it is responsible for energy caption, operational load mitigation, WT stalling

and aerodynamic braking [63, 81]. Aerodynamic baking is used to stop the

turbine when strong wind threatens the operational safety. Therefore, avoiding

pitching failure is extremely important as it can lead in catastrophic

consequences. This subsystem is usually managed by a hydraulic actuator or

an electric motor. Even electric motors have a quicker response, they bear

lower stiffness and reliability than hydraulic systems have. As it is said by

Yaoyu in [71], “for large to extreme aerodynamic loading situations, hydraulic

systems are considered more fail-safe”.

Some faults of hydraulic systems produce operation instability [81], however the

premature brake activation [68] also compromises the correct operational mode.

Other examples of pitch controlling systems failures are: the reduction of the

hydraulic fluid effective bulk modulus [82] produced by the air contamination of

the hydraulic system [82], reduction of plant bandwidth and significant leakage

in the hydraulic system [82]. Both of these last couple of threatens produce

stability robustness reduction of the corresponding closed-loop system.

Asymmetry in pitch angle [71] produces the WT shutdown during operation.

Furthermore, control signals can be used to the detection of some blade

pitching faults as the excessive backlash [83].

3.2.6 Tower and Foundation

WT tower and foundation are both critical components due to the fact that they

simply cannot be replaced as other components could. Therefore, some

potential failures as fatigue, cracks and corrosion must be regularly controlled

by inspections in order not to disembogue into WT collapse because, even

30

though a WT is designed for an operational life of twenty years, some

phenomena can represent a worse threaten than the expected during the

design phase of the WT. These phenomena could be an earthquake,

unexpected soil instability or the excessive algae/underwater grown on the

foundation, among others.

3.2.7 Power electronics and electric controls

Electronic controls represent the 13% of the overall WT failures even its

commissioning costs are just the 1% [71]. For that reason, enhancing its

diagnostic techniques is crucial. Besides it is important to notice that power

electronics represent much higher cost percentage for variable speed and direct

drive WT than for constant speed WT [68].

Some studies determined that most of Power Electronics System failures occur

due to semiconductor failures in the power electronics circuits. Thus some

questionnaires were conducted for researching these devices failures [106]

focusing the effort on the 3-phase Power Converters major faults, which are:

open circuit, short circuit and gate-drive circuit faults.

Questionnaires concluded that “because of the time criticality of these faults, the

fault detection and diagnostic methods for these semiconductor devices should

be implemented as protection functions instead of monitoring functions”.

3.2.8 Generator

The WT generators are among the subsystems with higher failure rates. Those

failures are mostly presented on the stator, the rotor and in the bearings. For

IM, which are the most common, about the 40% of failures occur to bearings,

the 38% to the stator and the 10% to the rotor; as the study “Condition

monitoring of wind generators” affirms [91].

Some of the major failures of these machines are: opening or shorting inter-turn

failures at stator’s or rotor’s winding circuits, stator winding abnormal

connection, dynamic eccentricity, broken rotor bars, cracked end-rings, static

and dynamic air-gap eccentricities, etc. Those failures consequences, which

31

can be also considered potential faults, are among others: unbalances and

harmonics in the air-gap flux and phase currents, increase on torque’s

pulsation, decrease on the average torque, higher losses, loss of efficiency and

winding’s overheating.

On another study performed by Xiang et al [95], power signal was utilized to

rotor misalignments detection and bearing faults using two techniques that will

be better explained on the following section. These are Faster Fourier

Transform and Wavelet analysis. Even these generators have rugged rotors;

some of its defects sill happening; like broken bars, cracked end-rings, shaft

bending and eccentricity [71].

One of the most important electrical faults that affect these machines is the

shorted winding coil, which reduces the generator synchronous reactance. It is

categorized as critical and immediate remedial action must be carried out right

after its detection. J. Tavner, et al [84] performed an investigation of shorted coil

diagnosis in 2009 called: “Condition monitoring and fault diagnosis of a wind

turbine synchronous generator drive train”. On this study and through

derivation, it was demonstrated that higher mechanical torque is needed to

obtain equal shaft rotational speed when shorted coil is produced. Besides, it is

known that shorted winding coil failure is usually produced much faster, in the

order of minutes, instead of the days or months that a mechanical degradation

failure needs to take place.

Rotor fault types can be divided into rotor eccentricity, breakage of rotor cage

bars and breakage of end-rings. Those failures are responsible of producing

some secondary faults that cause serious malfunctions as for example: winding

and excitation unbalance or inter-turn short circuit.

Rotor eccentricity exists when a non-symmetric airgap is produced between the

stator and the rotor when the second one is moved out of its position in the

center of the stator bore [107]. The maximum permissible level of eccentricity is

between the 5% and the 10% of the airgap length [108]. However, it must be

rapidly detected, as the motor is damaged progressively due to the fact that,

32

when the stator rubs the rotor or vice versa, catastrophic consequences to the

winding, stator core and rotor cage are produced [107, 109].

As it is explained by Mehrjou in [97], “rotor bars can be partially or completely

cracked during the operation of Squirrel-Cage Induction Machine (SCIM), due to

stresses and/or improper rotor geometry design”. Bar breakage constitutes the

worst failure for the SCIM rotor because when it happens, neighboring bars

deterioration starts as a result of higher stresses. The most probable

consequences of this failure are: unbalanced currents and torque pulsation;

which imply the average torque reduction [110].

33

Rotor (Hub) REF Blades REF Generator (bearing stator and

rotor) REF

Aerodynamic asymmetry 69 Cracks 71 Inter turn short circuit 96

Yaw misalignment 70 delaminations of the composite 72 Abnormal connection of the stator

winding 93

Creep and corrosion fatigue 68 surface wear 73 Dynamic eccentricity 102

Catastrophic failure 68 Increased roughness due to ice,

erosion, insects, etc. 74

Opening or shortening of stator or rotor winding circuits

91

Hub spinng on shaft 68 fatigue 76 spikeness 87

shaft misalignment 71 lightning strikes 79 rotor broken bar 97

Torsional oscillation 84 high vibrations 75 rotor cracked end-ring 97

Shift in the torque-speed ratio 84 flapwise fatigue damage 77 bent shaft 98

Mass imbalance 85 unsteady blades airloads 78 Excessive stresses 99

Pitch control REF blade fracture 68 static and/or dynamic air gap

eccentricities 102

Premature brake activation 68 unsteady performance 78 increased torque pulsation 100

Inability of excessive operational load mitigation

63 Loose of blade hub-connection 104

corrosion Excessive heating in the winding 93

operation instability due to hydraulic system failure

81 Gearbox (bearings and gears) REF Increase in losses and efficiency

reduction 101

Air contamination in the hydraulic system

82 Gears overload 87 Rotor misalignment 95

inability of aerodynamic braking 81 Gear tooth damage 86 unbalances and harmonics in the

air gap flux 92

34

Hydraulic fluid bulk modulus reduction

82 Pitting 86 Shorted winding coil (reduction in generator reactance)

85 Leakage in the hydraulic system 82 Cracking 86

Asymmetry in pitch angle 71 Gear eccentricity 84 Power electronics and electric

controls REF

Excessive backlash 83 Tooth crack 84 semiconductor devices defects 76

Tower and Foundation REF Shaft-Gearbox coupling failure 68 open circuit failure in 3phase

power converter 76

fatigue Spalling (due to internal stresses) 84 short circuit failure in 3phase

power converter 76

cracks Scratching (abrasive wear) 86 gate-drive circuit failure in 3phase power converter

76 corrosion Scoring (adhesive wear) 86

workboats/crane vessels/jack-ups impact

Lubricant viscosity changes 88 overheating

algae/underwater life growing on the foundation

Lubricant loss of water content 89 Error in wind speed/direction

measurement 68

soil instability Presence of additives/debris in the lubricant

90

earthquakes

resonance (height>100m)

Scour

Table 1 Technological Risk identification

35

3.3 Condition Monitoring Systems

3.3.1 Introduction

CM is the process carried out by observing WT components and structures for a

period of time to perform the assessment of its state and detect any change that

may constitute an early indication of impending failures [43]. Therefore, these

processes have been designed to identify incipient failures, so preventive

actions can be performed in order not to allow those failures to become

catastrophic events [44]. Moreover, these systems constitute an appropriate

method of improving WFs performance due to the significant cost benefits that

represent [50].

The monitoring can be carried out both using automatic or manual

measurement. Thus, some of the most used condition monitoring techniques

are among others [43]:

Vibration Measurements and Analysis (M&A).

Oil debris M&A.

Temperature M&A.

Strain gauge M&A.

Acoustic M&A.

Figure 7 shows the information flow of how CBM can be done to a system that

uses CM techniques.

36

Figure 7 Schematic flow of condition monitoring information

Source: [43]

In order to prevent further damage on the WT, CM systems are provided with

predefined triggers that start a sequence event when detected. For instance,

they could be an alarm to the Local SCADA System or a message to the

monitoring centre. CM is mainly associated with the next information types [43]:

I. Time Waveform Records of a specific time interval, which are

exchanged in real time or by files for analysis (i.e. acceleration, position

detection, speed, stress detection).

II. Status information and measurements representing the WT operation

conditions.

37

III. Results of time Waveform Record Analysis of Vibration data (scalar,

array, and statistical values, counters and status information).

IV. Results of different analysis as oil debris.

Until 2006 there was little documentation about WT CM [46-49]. However, due

to the high importance that renewable energies and particularly wind energy

have gained during the last decade, lot of effort has been made into CM and

fault diagnosis techniques research [45].

In these reports it is showed that most WT subsystems fail during operation as:

Rotor, Blades, Pitch Control System, Gearboxes, Bearings, Yaw System,

Generator, Power Electronics, Electric Controls and Hydraulic and Mechanic

Brakes among others [51-53]. Thus, a study was conducted by Tavner et al,

where WT main failures were identified based on eleven years of WT failure

data [48]. Thanks to this and other studies, most of the main WT Subsystems

monitoring and diagnostic techniques are provided.

3.3.2 Gearbox and Bearing

Gearbox faults constitute the leading issues for WT Drive Train CM among all

subsystems [46-49, 53]. Vibration measurement and Spectrum-Analysis are the

usual monitoring and diagnostics techniques. For example, a Vibration

Spectrum study, where the Wavelet Neural Network was employed, was

presented by Huang in [54]. Thus, for variable speed WT operation, Wavelet

Analysis was approved for feature extraction [46]. Moreover, a neural diagnostic

network for gearbox was developed from the Wavelet analysis of vibration

signals in [55].

The Acoustic Emission sensing is a technique that identifies the surface stress

waves produced by the rubbing action of failed components. This technique is

an appropriate improvement to the gearbox diagnosis and monitoring Vibration-

Based Methods, particularly for pitting, cracking or other potential faults

detection. Another study about the drive train diagnosis of synchronous

generator WT was carried out in [56]. There, the Discrete Wavelet Transform is

38

used to manage the high noise level present in WT signals. Moreover, electrical

analysis was used to the diagnosis investigation of gear eccentricity.

To conclude, the most used Gearbox CM techniques are listed in the table

below. Table 2 also shows the advantages/disadvantages and the monitored

components [45].

Table 2 Summary of typical gearbox Condition Monitoring Techniques

3.3.3 Generators

WT generators usually produce bearing, stator, and rotor faults. In [57] it is

shown that about 40% are bearings’ failures, 38% stator’s and 10% rotor’s.

Within the same study [57], fault diagnosis of doubly fed IM and Current

Signatures Analysis were deeply examined.

Detection of generator’s rotor misalignments and bearing faults were done in

[58] using both the Faster Fourier Transform (to determine precisely the

harmonic components amplitude, in order to obtain the peak amplitude

spectrum of the wavelet coefficients) and wavelet analysis (to generate Time-

Frequency representation of non stationary signals), resulting on an early stage

of failures successful identification.

39

Shorted winding coil is a critical electrical fault, for which, immediate protection

or remedial action should be taken. Shorted coil was detected by using the shaft

speed in [49] but was later (2009), when the wavelet analysis was used for the

shorted coil diagnosis study [56]. Finally, the current, voltage, power and torque

speed signals were all declared effective for shorted coil detection.

A model based diagnosis study was conducted in [59] for doubly fed IM WT for

the faulty physical parameters identification. The result was a time-stepped

coupled circuit model that includes a winding and excitation unbalance on both,

stator and rotor.

3.3.4 Power Electronics and Electric Controls

Electronic controls just imply about the 1% of the total WT cost. Nevertheless

there are responsible of the 13% of faults. Thus, power electronics costs are

considerably higher for variable-speed turbines rather than constant-speed

turbines. However, diagnosis of power electronics is very hard due to the

extremely little time between the failure and its catastrophic consequences and

therefore, the suggestion of using redundant controls was made by in [53] and

later discarded due to the high cost that it implies.

Moreover, most of power electronics system failures are produced on its

semiconductor devices, so an exhaustive survey for its diagnostic was

conducted by McGowan in [53], focusing on the major system failures: open

circuit, short circuit and gate-drive circuit failures. It was concluded that fault

detection and diagnostic methods for these semiconductor devices should be

implemented as protection functions instead of monitoring functions.

3.3.5 Rotors, Blades and Hydraulic Controls

WT rotors are subject to creep fatigue and corrosion fatigue, which are

produced as cracks and blade delaminations. Diagnostic of blade faults was

studied by McGowan in [53] using Strain Measurement Techniques like FBG

(fiber optic bragg grating) and Acoustic Emission. For small WT blades,

40

piezoelectric impact sensors were used in [61], while Acoustic Emission

sensors were used for faults detection [62].

Blade pitch control systems are crucial for WTs operation, as pitching is a

determinant mechanism that enhances energy capture, mitigates operational

loads, stalls and constitute an aerodynamic brake [63, 64]. Therefore, avoiding

pitching failures is crucial for the effective WT operation. Asymmetry in pitch

angle might suppose the necessity of shutting down the WT during operation.

For that reason, blade pitching faults detection is a very relevant diagnostic

measure.

MLS Electrosystem has published in [65] the predictive maintenance methods

used for blade pitch control systems and General Electric has described their

carried work in blades angle asymmetry diagnostics in [66]. For further work it is

recommended to explore diagnostic signatures from the control signal of the

hydraulic pitch system to enhance valves and drive paths faults identification

based on important Dynamic Models [67].

3.4 O&M risk identification

3.4.1 Introduction

Section 3.4 has covered the risk identification process for all those activities

related with WT O&M, as it is believed that only the good management of these

assets will make the life extension process come true.

This process has been elaborated from a document created by The Crown

State, The Scottish Enterprise and GL Garrad Hassan called “A Guide to UK

Offshore Wind Operations and Maintenance” [105], which has been really

useful, giving the author the possibility of getting inside OWT O&M world.

Along this section the O&M activities have been divided in different relevant

areas and analysed. These areas are:

41

Offshore logistics

Onshore logistics

Back office, administration and operations

Turbine maintenance

Array cable maintenance

Foundation maintenance

Export cable and grid connection.

It is expected that this section helps to mitigate some of the identified risks and

also to optimise WT performance and maintenance, so the life extension

process could be reached.

3.4.2 Offshore logistics

This activity requires the management of the offshore necessary equipment and

the organization plans and resources required to safely transport of both,

technicians and equipment at sea, including workboats, Offshore Bases,

helicopter services, jack-ups, among others. Besides, safety access to the WTs

and other project infrastructures (ie. Offshore substations) must be ensured.

Nowadays that Round 3 is going to be soon developed, there are some risks

that, even they were present also in the other two Rounds, have gained

relevancy. Their correct management, assessment and mitigation (if possible)

are crucial for the optimal O&M strategies. Some of them are:

Low accessibility due to high weather and sea-state dependency.

Everything must be ready for the good weather and sea conditions

window, so work can be done as soon as possible, minimizing the WT

downtime, which constitutes a financial risk for the project. The more the

WT is shut down, the higher production losses.

Number, size and reliability of turbines.

Distance from onshore facilities, which implies long transit times and

therefore, less time spent on active work.

Offshore substation design.

42

Besides the quantity of WTs and its reliability, the factor that represents a higher

influence to OW O&M strategies is the distance between the OWTs and the

onshore facilities. As Round 3 is developed, this distance, in general, will tend

to increase, which would imply a change from the typical strategy to another

one more suitable to very distant offshore emplacements.

Means of reducing transit times and increasing accessibility to OWT currently

being used are among others, workboats and helicopter services. Whereas

workboats are not very expensive and are able to carry high number of

technicians, its response time and accessibility are heavily affected by transit

time and sea conditions. On the contrary, helicopters are more expensive and

do not have the chance of carrying as much technicians and equipment than

workboats. However helicopters present quickly response, have very short

transit times and high accessibility as they are able to operate without being

influenced by sea conditions (although poor visibility). Besides, maintenance

and repair actions should be able for all transportations methods, just in case

they brake.

Furthermore, it is important to accentuate the fact that there are other important

site-specific factors which must be taken into consideration by offshore logistics,

such as unexpected equipment payloads that can affect its transportation,

aviation regulations, safety considerations and suitability of available ports.

3.4.3 Onshore logistics

Onshore services are critical for offshore logistics supporting due to the fact that

O&M activities require access to port facilities such as load out and work boat

mooring. As it was previously stated, the distance between the offshore

emplacement and the onshore port is a key driver, sometimes powerful enough

to create new infrastructures much closer to the project, even other facilities

were already created, but farther. For that reason, an O&M port base will

always be required. Also helicopter facilities, such as a landing-pad, re-fuelling

facilities and a hangar, are usually built nearby to provide technicians an easy

and quickly access to the helicopter or vessel. However all of these facilities

43

require either maintenance or a good management in order that they can be

combined and used efficiently.

Other drivers include availability and appropriateness of existing facilities as

well as onshore access and infrastructure. Moreover, constant On&Off

communication must exist. Besides, there is a recent tendency of adopting a

multi-port strategy with different locations of specific activities, each one with the

most appropriate facilities. This is the case of the everyday personnel and light-

equipment transfers, which benefit hugely from short transit times, while WT

inspections or scheduled replacements are less distance sensitive but might

need higher load-out and crane capacity.

3.4.4 Turbine maintenance

Turbine maintenance activities regard to four main elements: inspections,

scheduled and unscheduled maintenance, provision of spare parts and

technicians training. Maintenance is usually divided into preventive (no failure

occurred) and corrective (a failure already occurred) works. The majority of

preventive works is strategically carried out to minimize the production losses,

which usually means in periods of low wind speeds, but it is not always

possible. Corrective maintenance has to be coordinated and performed as soon

as possible, as all the downtime until repair means economical losses.

A variety of well qualified technicians are required for maintenance and

inspections labors in order to maximize safety and minimize human errors.

Some of the profiles required are mechanical or electrical engineering, with

further WT maintenance training usually given by the WT provider, offshore

survival training as working at height and climbing skills and additional specialist

skills as could be, for example, HV equipment training or certification to carry

out lifting and climbing Equipment Inspections. As it can be appreciated these

skills are quite uncommon for “normal” technicians, which leads into a high

demand.

44

Well spares management and stocking is another aspect which has crucial

importance. During the warranty period, spares are provided by the WT

supplier. However, once this period is over, the owner has the chance to search

for alternative suppliers which provide generic pieces. Spares lead time and

manufacturing and transporting defects are potential risks that might be

managed either onshore (in the large warehouse where they are stored) or

offshore during the maintenance labors.

Revenue losses produced by downtime mean that significant delays due to

parts shortages are not an option. Large replacement components can often be

taken off the turbine production line, making the lead time required to get a jack-

up on site the highest delay.

3.4.5 Export cable and grid connection

These activities regard to the necessary technicians and equipment to carry out

the inspections and reparations in the interconnection of the OWF to the

onshore Power Transmission System, which includes both, Onshore&Offshore

(On&Off) electrical substations and their electricity exporting cables. For On&Off

substations, transformers and other relevant equipment; electrical faults as

transformer failures, overvoltage/overcurrent, overheat and consequently fire,

are the most common, among others.

Little maintenance is usually required to onshore cables, which are very reliable

in general. Occasionally, faults requiring additional cable, jointing facilities and

sometimes, even an excavator, might occur to underground cables and

electricity exporting cable surveys may be needed to assess whether the cable

depth is appropriate. Buried cables can also present faults due to the fishing

activities that take place around the OWF (due to the abundance of aquatic life

generated by the algae grown in the foundations and sub-aquatic structures).

Those surveys frequency depends mainly on seabed mobility and results of the

initial surveys. Export cables might present faults either as a result of insulation

damage (uncommon), defects or external damage, like the one that an anchor

or a fishing strike could entail.

45

Export cable faults might produce the absolute WF’s output loss. For this

reason and also because its reparation techniques still not being completely

developed, in comparison to similar sectors, maintenance and surveys of this

asset are likely to be the subject of greater urgency.

3.4.6 Array cable maintenance

Array cable maintenance regards to the technicians and equipment necessary

for the inspection and retrieval of the subsea cables that interconnect WTs and

unify the power plant. Array cables are those located beneath the seabed,

connecting the WTs to the offshore substation. They present similar physical

requirements of surveying and repairing than the export cables. However their

downtime is higher in magnitude and the response times are generally slower.

Subsea cables are provided, in most of the cases, with five years of warranty.

However it just covers manufacturing defects. Thus, almost the totality of array

cable failures are related to cable movements, exposure by tides or sediment

flows; and in some cases, failure due to anchor strike or external aggravation,

none covered by warranty. Therefore, owners have the responsibility of

monitoring, repairing and performing several types of surveys to the cables,

although it might be noticed that its maintenance strategies still being quite

immature in this industry.

Inspections and underwater operations in general are carried out by Remotely

Operated Underwater Vehicles (ROVs) due to the high risks that diving entail.

Although there is not another option, diving inspections are not carried out.

3.4.7 Foundation maintenance

Foundation maintenance involves the technicians and facilities necessaries to

WTs foundations and subsea structures inspection and repair. It is natural to

believe that WT foundations are also provided with the same kind of warranty

WTs have; however, they are usually not. Instead, foundation risks are

insurable and can be mitigated through certification.

46

Therefore, its maintenance has to be carried out in a different way; mostly by

visual inspections and survey work, while performing those risks remediation

labors only if it is completely necessary. These different types of inspections

assess the structural strength, lifting, climbing and safety equipment, corrosion

and scour protection. Foundation and sub-sea structures maintenance includes

painting reparations, excess of marine growth removing and rock placing to

enhance foundations risk mitigation against scour and occasional reparations to

wave-damaged tower facilities such as stairs, gates, grills and platforms.

During the first two years, some surveys are carried out in order to ensure the

structural integrity of the turbine foundation but, once the site has been

assessed, those activities become infrequent, being just necessary once every

5 or 10 years. The quality of the protection placed specifically to prevent the

erosion caused by some sediment on the foundation-seabed interface can be

evaluated with sonar scans from the surface (ie, on a survey vessel), therefore

submersions and divers are not necessary.

3.4.8 Back office, administration and operations

This sector includes the analysis, health and safety Data Acquisition (SCADA),

IT and administrative assistance of the whole WF. There are some necessary

safety inspections that must be performed every six months/one year

approximately, within a WF. Some of them are related with: fall-stoppage

systems, davit cranes, boat landing and stairs, external gates and railings and

evacuation facilities. It is a common practice that WF owners train up some

technicians, as qualified personnel must carry out the inspections. Procedures

of H&S incidences must be taken as routine within O&M activities.

SCADA and CM constitute extremely important activities within a WF due to the

fact that are responsible of the WF optimization, correct performance and

potential components faults detection. Its analysis also helps to determine the

scheduled maintenance. Several dedicated personnel develop these activities

constantly (24 hours, 7/days a week) from the onshore base. Therefore those

systems failure will lead to catastrophic consequences to the WF performance.

Management and coordination of O&M activities is crucial to WF safety and

47

efficiency. A Senior Authorised Person (SAP) is the WF coordination

responsible person, which has to be present at any time in the base. SAPs also

coordinate 24/7 the personnel and vessels location of the project’s environment,

including the assessment of the monitoring devices.

Some administrative duties have to be performed for OW O&M activities. These

tasks include financial reporting, public relations, procurement, parts and stock

management, H&S management, “permit to work” controls and general

administration. Moreover, future operators, SAPs and technicians must be

trained either “in-situ” at the port base, or in a remote location such as company

headquarters, where also much other activities related with the plant can be

done.

49

Onshore logistics Offshore logistics Turbine

Maintenance Export cable and grid connection

Array cable maintenance

Foundation maintenance

Back office, administration and operations Condition

Monitoring System failure

Low accessibility due to unexpected bad weather conditions

Low availability of trained

technicians

Cable insulation damage

Movement of the subsea cable

Chemical spill

Corrosion Wrong prediction

of scheduled maintenance

Port facilities issues Human errors

during inspections and maintenance

Overvoltage/ overcurrent events

Exposure by tides or sediment flows

Weather risk

Multiple ports management

Long transit time (less time can be spend on

active work)

Structural damage due to the work

boat/jack-up/crane vessels impact

overheat in the onshore substation

Mechanical damage due to anchor strike

or external aggravation

Delay on spares Loss of

communications between

onshore-site and offshore

Spare manufacturing

defect

Disagreements between the

owner and other parties*

Quantity of turbine downtime (loss of

production)

Fire either in offshore or onshore

substation Spare lead time Insulation damage

Condition

Monitoring System failure

Transformer faults* Human errors during maintenance

Wrong measured SCADA data

Work boat, helicopter or jack-up breakdown

Disturbance of buried cables due to

fishing activities

Long transit time Weather risk

IT services failure

Bad response time Weather risk

Cable manufacturing defects

Condition

Monitoring System failure Transport problems

due to unexpected equipment payload

Remotely Operated

Underwater Vehicles (ROVs) breakdown

Low prices of E

sales

(E consumed by

helicopter/E produced)>1

Aviation regulations (affect helicopters)

Table 3 O&M activities risk identification

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4 A Cost Analysis Model for Risk Prioritization and

Maintenance Optimisation of Offshore WT Subsystems

4.1 Introduction

This model aims to become a tool for the economic analysis of the different WT

subsystems in order to determine how and when the WT could fail during its service

life and moreover, during a possible extended life. Besides, it also identifies which

subsystem makes greater impact on the system’s reliability and economy by

analysing not only every component’s failure frequencies but also its different

maintenance activities and their associated costs.

Two documents were mainly used for the analysis: an IRENA working paper called

“Renewable Energy Technologies; cost analysis series: Wind Power” (2012) [111],

where a WT cost breakdown is made and the NREL Technical Report called:

“Installation, Operation, and Maintenance Strategies to Reduce the Cost of Offshore

Wind Energy” (2013) [112].

The present model has been designed to constitute a tool for companies, being

easily adapted for every practical case they might have. For that reason, inputs can

be changed on the Excel sheets. Those inputs are:

Total cost of the WT: for this study a cost of 1970 USD/kW has been chosen

from Table 4.5 of [111] and has been included on Appendix A.1.

The WT rated power.

The Power Purchase Agreement (PPA) which in this case has been estimated

as 0.125 USD/kWh [112].

Every subsystem annual failure frequency [112].

The probability of occurrence of every maintenance category of each WT

subsystem [112].

The total cost of the WT subsystems, expressed as a percentage of the WT

total cost [111].

Among others more specific from the maintenance categories, like the logistics

and the additional costs, which have been explained in the following sections.

52

4.2 Baseline references

As it was done by Maples et al, in [112], a hypothetical 500 MW WF composed by

one hundred WT, each one with a rated capacity of 5MW and located approximately

25 nautical miles away from the coast of Virginia (USA), was chosen for the study.

The water depth at the WF emplacement is on 30 m average.

A 5 MW WT is used as it is considered a typical utility scale, multi Megawatt WT.

Those WT are also provided with a variable speed, collective pitch control system

connected through a high speed Drive Train, using a multiple stage Gearbox.

The WT is provided with an internal crane in order to lift small elements so as Pitch

Motors and Yaw Drives which don’t exceed a maximum weight of two thousand

kilograms. In order to lift these small parts, they have to be transported from onshore

to the platform located at the tower, near the sea surface and use the crane located

outside the nacelle. For large parts replacements as could be the generator or a

blade, a large crane is needed, like the one present on jack-up vessels. Table 4 and

Figure 8 show the specifications of the WT used by the NREL to perform the

analysis in [112] and the power curve of the same WT.

Table 4 WT specifications

Source: [112]

53

Figure 8 WT Power Curve

Source: [112]

4.2.1 Maintenance Categories

This model is based on the maintenance classification performed in [112] by Maples

et al, which divides the maintenance activities into six categories depending on its

severity.

4.2.1.1 Category One: Remote resets

WTs are shut down due to some warnings or errors. A summary of the action

sequence is:

I. The WT has to be shut down due to a warning.

II. The monitoring team inquires the potential causes of the warning, which takes

around two hours.

III. In case that the warning is declared not serious, the WT can be restarted

remotely without the necessity of carrying technicians to the turbine.

54

4.2.1.2 Category Two: Inspection and small repair inside the WT

In case that a small repair inside the turbine is required, three technicians are

necessarily going to the offshore emplacement, without more facilities than the

typical toolbox, to perform the inspection and repair. A summary of the carried work

is:

I. Technicians travel in a workboat from the onshore emplacement to the WT in

question, which takes an amount of time equal to the “transit time” (usually

two hours and a half).

II. Technicians are transferred into the turbine (~20 min).

III. Inspection or repair is carried out. Meanwhile, the workboat waits the

technicians in the WF. This activity takes between two and six hours.

IV. Technicians return to the onshore emplacement with the workboat, which

takes again the “transit time". A maximum of Vw = 12 m/s and Hs = 0.9 m are

permitted to transporting technicians and accessing the WT to carry out the

maintenance activities.

On average, an organization time of six hours is required to coordinate these

activities and usually, those have to be carried out within a normal working day (only

during daylight). However, they can be done in different days in case that weather

requires it.

4.2.1.3 Category Three: Inspection and small repair outside the WT

Within this category are included activities that must be carried out outside the WT

as blades scouring, gel coat repair and tower inspection. In case these activities are

required, two technicians are necessarily going to the offshore emplacement to

perform the inspection and repair. A summary of the carried work is:

I. Technicians travel in a workboat from the onshore emplacement to the WT in

question, carrying the necessary hoisting equipment. This activity takes an

amount of time equal to the “transit time” (usually two hours and a half).

II. Technicians provided with special outside equipment are transferred into the

turbine (~20 min). Number of technicians can vary but usually the crew is

composed by 3.

55

III. The repair facilities are lifted from the platform to the top of the WT, usually

the nacelle or the rotor and the facilities for lowering technicians are installed.

These activities take around one hour.

IV. A technician is hoisted from the hub along blade 1, and blade 1 is inspected.

Then he comes back to the rotor hub and a 120º rotation of the rotor is

produced in order to repeat the inspection of the second blade.

V. Step 4 is carried out again in order to perform the third and last blade

inspection. Equipment installation and inspection activities of all blades are

carried out in a period of time between six and ten hours.

VI. Technicians return to the onshore emplacement with the workboat, which

takes again the “transit time". A maximum of Vw = 12 m/s and Hs = 0.9 m are

permitted to transporting technicians and accessing the WT to carry out the

maintenance activities.

On average, an organization time of six hours is required to coordinate these

activities and usually, those have to be carried out within a normal working day (only

during daylight). However, they can be done in different days in case that weather

requires it.

4.2.1.4 Category Four: Replacement of small parts (less than 2000 kg).

Pitch motors or hydraulic system’s components constitute some examples of these

called “small parts”. In advance this term will be used for every part that weights less

than two thousand kilograms. These small parts have to be taken to the WT and

lifted with the internal crane from the WT platform to the nacelle. A summary of the

carried inspection and maintenance activities is:

Inspection

I. Technicians (three) travel in a workboat from the onshore emplacement to the

WT in question, which takes an amount of time equal to the “transit time”

(usually two hours and a half).

II. Technicians are transferred into the turbine (~20 min).

III. Inspection is carried out. Meanwhile, the workboat waits the technicians in the

WF. This activity takes between two and six hours.

IV. Technicians return to the onshore emplacement with the workboat, which

takes again the “transit time".

56

Replacement

I. Three or four technicians travel in a workboat from the onshore emplacement

to the WT in question, carrying the spare part. This activity takes an amount of

time equal to the “transit time” (usually two hours and a half).

II. Technicians are transferred into the turbine (~20 min).

III. In the circumstance that the replacement has to be carried out, the spare is

lifted to the platform with the small crane on the lower turbine platform, which

takes around one hour.

IV. The small part that needs to be replaced is disassembled and hoisted down

from the outside of the tower to the WT platform. This work is usually carried

out in a period of time between two and eight hours.

V. The replacement of the failed component is lifted from the platform to the top

of the nacelle by the internal crane that it posses. The activity takes around

two hours.

VI. The spare part is assembled in a period of time between 2 and 12 hours.

VII. The replaced part is put in the workboat with the help of the small crane

present at the platform, which takes around an hour.

VIII. Technicians return to the onshore emplacement with the workboat, which

takes again the “transit time".

The total maintenance activity will take between 8 and 24 h. A maximum of Vw = 12

m/s and Hs = 0.9 m are permitted to transporting technicians and accessing the WT

to carry out the maintenance activities, however the facilities lifting from the platform

to the nacelle just can be performed in conditions up to Vw = 10 m/s. Spare parts for

this category are kept in stock at the harbor.

On average, an organization time of twelve hours is required to coordinate these

activities and usually, those have to be carried out within a normal working day (only

during daylight). Furthermore, they must be done in just one period of time in which

the weather conditions must be appropriate due to the fact that this maintenance

activity cannot be split.

57

4.2.1.5 Category Five: Preventive replacement of small parts

It is based on the assumption that some small parts (previously defined) might need

a preventive replacement due to the detection of high level of degradation on them.

This is commonly known as Condition-based Maintenance, which presents some

advantages as could be the downtime reduction, due to the fact that the WT has just

to be shut down during the replacement and it is not influenced by the logistic,

organizational, weather, and travel downtimes that the failure of the same part would

imply. The maintenance procedure for this category is the same than the one carried

out in category number four, therefore there is no necessity of explaining it again.

4.2.1.6 Category Six: Replacement of large parts with large external crane on

jack-up vessel

A large crane placed on a jack up vessel is necessary to lift large parts (heavier than

2000 kilograms). This kind of replacement could be, for example, the transformer,

the generator or a blade. A summary of the carried work is:

Inspection

I. Technicians (three) travel in a workboat from the onshore emplacement to the

WT in question, which takes an amount of time equal to the “transit time”

(usually two hours and a half).

II. Technicians are transferred into the turbine (~20 min).

III. Inspection is carried out. Meanwhile, the workboat waits the technicians in the

WF. This activity takes between two and six hours.

IV. Technicians return to the onshore emplacement with the workboat, which

takes again the “transit time".

58

Replacement

I. Technicians travel in a workboat from the onshore emplacement to the WT in

question, which takes an amount of time equal to the “transit time” (usually

two hours and a half). This action will be done every working day until the

replacement ends.

II. Technicians are transferred into the turbine (~20 min).

III. The large part that has to be replaced is disassembled. This activity takes

between 4 and 8 hours.

IV. The replacement of the large part is brought from the harbor to the WF by the

jack-up vessel, which takes around 8 hours from the onshore emplacement.

V. The jack-up is appropriately placed (one hour).

VI. The faulted part is removed and hoisted to the jack-up vessel and the pare

part is lifted to the nacelle. These activities take between six and 10 hours.

VII. The replacement is mounted crudely (two hours). When the part has been

totally assembled, the WT can be put again into operation. This will be done in

a period of time between twelve and twenty hours, depending on the

component.

VIII. Technicians return to the onshore emplacement with the workboat, which

takes again the “transit time".

The total maintenance activity will take between 24 and 40 h. A maximum of Vw = 12

m/s and Hs = 0.9 m are permitted to transporting technicians and accessing the WT

to carry out the maintenance activities, however the facilities lifting to the nacelle just

can be performed in conditions up to Vw = 10 m/s and jack-up placing up to 2.5 m of

Significant Wave Height. Spare parts for this category have to be ordered to the

supplier, which will send them to the onshore emplacement in a period of time

(called “spare parts logistic time”) of approximately one or two weeks.

On average, an organization time of 24 hours is required to coordinate these

activities and usually, those have to be carried out within a long working day (during

day and night). Furthermore, they must be done in just one period of time in which

the weather conditions must be appropriate due to the fact that this maintenance

activity cannot be split.

59

4.2.2 Equipment

In order to carry out all these maintenance activities that have been described

above, different access equipments have to be used. This access equipment is

composed by:

Workboat access vessel (used for both, technicians and small parts

transportation)

Jack-up vessel (used for the transportation and large spares elevation)

Cable-laying vessel (used for cable replacements)

Diving support vessel (used to perform underwater inspections and repairs)

Turbine cranes (used to lift small spares from and to the workboat.

Each one is characterized by different costs and logistics/travel times. On the table

below, the logistic time, the transit time, cost of MOB/DEMOB and the additional

costs are listed for all the different access equipment.

Equipment Description

Time logistic

Equipment (hr)

Transit time (hr)

Cost Equipment for

MOB/DEMOB (USD/mission)

Additional cost

equipment during

travelling (USD/trip)

1. Workboat 0 2.6 - 500

2. Jack-up barge (100MT) 720 - 440000 310000

3. Cable layer 720 - 560000 190000

4. Diving support vessel 360 - 190000 95000

5. Turbine crane - - - -

6. Blade inspection - - - -

Table 5 Equipment Description: associated costs and logistic times

“Transit time” is defined as the amount of time that takes for a workboat to arrive

from the harbor to the offshore emplacement. Transit time for jack-ups, cable-laying

vessels, and diving support vessels has not been modeled due to the fact that, even

those types of vessel take some time travelling to the WF, worse weather conditions

are allowed for their transit. If their transit time would have to be modeled, the waiting

time for these vessels would be overestimated.

60

“Logistic time” represents the time that takes for all those vessels listed above, (all

except workboats) to get to the offshore emplacement since they were chartered.

The values on the table above are the average between the four season values. All

of these values have been taken from [112].

“Cost MOB/DEMOB” symbolizes the cost that take the mobilization and

demobilization of the equipment and the limited availability of those vessels. Their

costs were estimated by [112] from the Obdam & van der Zee publication of 2011.

To conclude, the “Additional cost of equipment during travelling” represents the

equipment fuel costs (ie, going to the offshore emplacement and coming back will

take approximately five hours, with an estimated fuel cost of $100/hr, implies a fuel

cost of $500 per trip).

4.3 Assumptions and estimations

As it was stated before, two main documents were used to build the model, [111]

and [112]. However, as each study had different bases, some assumptions were

necessarily made in order to unify both of them and be able to perform the analysis.

Some of these assumptions are related with the WT components breakdown, as the

subsystems cost [111] and failure frequencies [112] had to be related. These

assumptions were:

The rotor system from [112] is equivalent to the rotor hub and blades from

[111].

The drive train from [112] is equivalent to the rotor bearing, main shaft,

gearbox and main frame from [111].

The hydraulic system and blade adjustment from [112] is similar to the pitch

system in [111].

The generator, generator control and protection system and the generator

lead/transmission cables from [112] are equivalent to the generator system

from [111].

61

Therefore, the final failure frequency and cost values of every subsystem are:

Subsystem Rotor

System Blade

Adjustment Hydraulic

System Drive Train

Yaw System

Generator

Control and protection

system (generator)

Generator Lead/

transmission cables

Transformer Machinery Enclosure

Tower

Turbine control &

protection system

Windfarm Cables

Annual Failure

Frequency 0.131 0.978 0.054 0.289 0.508 0.325 0.600 0.465 0.080 0.014 0.151 0.862 0.050

% of the Total cost

23.57 2.66 18.84 1.25 3.44 3.59 1.35 26.3 0.1 0.96

Cost (million

USD) 2.322 0.262 1.856 0.123 0.339 0.354 0.133 2.591 0.010 0.095

Table 6 WT Subsystems' failure frequency and cost

62

The following two assumptions were taken from [112] and made, in order to be able

to model the necessary equipment described above:

For the WT crane and blade inspection facilities, no logistic time, travel time,

and costs are recorded. For both, the WT crane and blade inspection

facilities, a Significant Wave Height up to 0.9 meters is established, due to the

necessity of transferring technicians to the workboat at any time during

operations.

All vessels are assumed to be leased when required for maintenance. For the

jack-up barge, cable-laying vessel and diving support vessel, a mobilization

time was assumed in order to take into account the availability limitation that

those vessels can experiment. That is not workboats situation.

Other important assumption is that cascade failures and other subsystem’s failure

influences have already been included in the failure frequencies. Thus there are

other assumptions related to the cost analysis that would be later explained on the

methodology of this study, as it is consider that these assumptions would be better

understood there.

In order to calculate the loss of revenue produced when the turbine is shut down, the

estimation of the WT annual electricity output is required. Therefore this estimation

has been done with an online tool available in [113] where, by setting the values of

some parameters the estimation was made.

Those parameters were:

Rotor Diameter: 126m

Mean wind speed: 12 m/s (which was the maximum allowed)

Cut-in speed: 3 m/s

Cut-out speed: 25 m/s

Turbine efficiency: 45% (according to Figure A-2 from Appendix A [112])

Weibull shape parameter: 1.5 (in this case it is assumed but a company could

easily calculate it for the specific location)

Therefore, the predicted WT output would be: 68 848 718 kWh per year.

63

4.4 Failure frequency study along the service life and life extension

On the first page of the Excel file, the accumulated failure frequency of each

subsystem was derived from the annual failure frequency and the different

maintenance categories for both, a service life of 20 years and a life extension period

of 10 years.

Moreover, by the estimation of each maintenance category’s probability of

occurrence, (which in this case has been taken from [112]) a comparison between

the number of failures of each maintenance category and its severity can be done.

The following equations were used to calculate the annual failure frequency for each

maintenance category (( ) ), which is the annual failure frequency (AFF)

times the probability of occurrence of this maintenance category

(( ) ) on a specific subsystem, and the “accumulated failure

frequency of each maintenance category” (( ) ) at a specific year (Y), which is

expressed as “the annual failure frequency of the previous year”, plus the annual

failure frequency, everything for each maintenance category of every subsystem.

( ) ( ) (4-1)

( ) ∑[( ) ]

( )

(4-2)

[( ) ]

(4-3)

An example of the whole procedure and the table of results can be seen either on

the Appendix or on the first page of the Excel file. Therefore, this analysis is useful to

investigate HOW and WHEN the system might fail in different ways [( ) ]

and also to perform a prioritization of the critical subsystems so greater effort can be

made on its risk mitigation.

From this analysis it can be concluded that critical subsystems of the analysed WT

are the generator, yaw and pitch systems and drive train.

64

4.5 Maintenance activities Cost Analysis

The aim of this study was to make a comparison between the total amount of money

maintenance activities need depending not only on the subsystem’s cost, but also on

the severity of the failure (the category) and the frequency that, approximately, these

maintenance activities have to be carried out along the service life and the life

extension period, in order to determine whether these cost and the magnitude of

their impact over the system can be reduced.

On the Excel page called “Maintenance categories and downtime” the variables

which directly affect the maintenance activities were settled for each one. It must be

noticed that these Excel sheets have been created in order to become a useful tool

for those companies that manipulate experimental data. Therefore, these parameters

are written in red in order to being identified as “inputs”. Some of these variables are:

the crew necessary to carry out the work, the repair time and its costs, the strategy

and necessary equipment, the equipment logistic time, which is the time that takes

the equipment (for example a jack-up) to be chartered and travel to the

emplacement, the spares logistic time, in case the owner does not have the

necessary spares and the transit time, among others.

While Table 7 shows the different maintenance categories and some of their factors

that influence their study, Table 5 shows the different equipment possibilities and

their particular parameters (already explained in the “baseline references” section).

Equipment Description Time logistic Equipment

(hr)

Transit time (hr)

Cost Equipment for MOB/DEMOB (USD/mission)

Additional cost equipment

during travelling (USD/trip)

1. Workboat 0 2.6 - 500

2. Jack-up barge (100MT) 720 - 440000 310000

3. Cable layer 720 - 560000 190000

4. Diving support vessel 360 - 190000 95000

5. Turbine crane - - - -

6. Blade inspection - - - -

Table 5 Equipment Description: associated costs and logistic times

65

Maintenance categories

Nr

Description

Total downtime

(hr) Crew (Nr) Repair time (hr)

Repair Costs

Repair Strategy Logistic time (hr) Transit time (hr)

Access

equipment 2nd

Device 3rd

Device Equipment

logistic Spare parts

Organisation

Remote Reset 1 none 0 2 none

0 0 0 0

2

Inspection and small Repair Inside

2 small 3 4 consumables 1

0 0 6 2.6

12.6

Inspection and small Repair Outside

3 small 3 8 consumables 1 5 6 0 0 6 2.6

16.6

Replacement small parts (<2MT) internal crane

4

small 3 8 low 1 5

0 0 12 2.6

22.6

small 3 16 low 1 5

0 0 12 2.6

30.6

large 4 16 medium 1 5

0 0 12 2.6

30.6

large 4 24 medium 1 5

0 0 12 2.6

38.6

large 4 24 high 1 5

0 0 12 2.6

38.6

Preventive replacement Small parts (< 2 MT)internal

crane 5

small 3 8 low 1 5

0 0 12 2.6

10.6

large 4 16 medium 1 5

0 0 12 2.6

18.6

Replacement large parts (< 100 MT) large external

crane 6

large 6 24 medium/high 1 2

720 168 24 2.6

744

large 6 24 high 1 2

720 336 24 2.6

744

large 6 40 medium/high 1 2

720 336 24 2.6

760

large 6 40 very high 1 2

720 336 24 2.6

760

Table 7 Maintenance Categories Description

66

All these new inputs are defined with the aim of calculating the total time that the WT

has to be shut down when a failure occurs or a preventive maintenance has to be

carried out. This “Downtime” is used to calculate the loss of revenue that these

necessary or preventive maintenance activities produce. The formula used to

calculate the total downtime was:

( ) (4-4)

However some assumptions were made for these calculations:

For preventive replacements (maintenance category number 5) it was

assumed that neither the organization time, which represents the time

required to coordinate the maintenance activity, the equipment and spares

waiting time (all of them part of the logistic time), nor the transit time, are

included on the downtime due to the fact that the WT can still working during

these periods.

For large parts replacements (maintenance category number 6) it was

assumed that the organization time and the spares waiting time is included on

the jack-up waiting time, as since the moment the operator realize that a large

replacement has to be done, the jack-up can be chartered and until it arrives

the spare can be ordered and the organization of the activity can be planned.

Moreover, the transit time, which is the time that takes to get from the port to

the base, has just been considered for the workboats and assumed that it is

included on the logistic time for other equipment.

Once the downtime has been evaluated for every maintenance category, the

calculation of the total loss of revenue of each maintenance activity for each

subsystem can be made with the following formulas:

( ) (4-5)

( ) ( ) ( ⁄ ) (4-6)

( ) ( ) (4-7)

67

( ) (

⁄ ) ( ⁄ ) ( )

⁄

(4-8)

Where:

( ⁄ ) (4-9)

( ⁄ ) (4-10)

It must be noticed that, in the crew cost calculation, the term “hours of work” is just

related to the hours that technicians are working on the WT and does not take into

account the transit time that technicians are travelling to/from the offshore

emplacement. Besides, technicians’ salary has been estimated as 125 USD/hr from

this practical case [112]; however it can be easily changed on the Excel file in case

of necessity.

Repair costs are referred to the percentage of the subsystem that has been affected

by the failure or has been to be replaced. It also includes the spares and the tools

used for carrying the activity; therefore, depending on the severity of the

maintenance activity, a percentage of the total cost of the subsystem has been

established as this cost. However, it must be noticed that these estimations are

assumptions, due to the fact that no suitable data were found for this parameter on

the references. Those percentages have been written in green on the Excel file with

the aim of being identified as “assumed data”. This data is recorded in table 8:

Maintenance categories Nr

Description

Repair Costs % of

subsystem's cost

Remote Reset 1 none 0

Inspection and small Repair Inside 2 consumables 30

Inspection and small Repair Outside 3 consumables 40

Replacement small parts (<2MT) internal crane

4

low 60

low 60

medium 70

medium 70

high 90

68

Preventive replacement Small parts (< 2 MT)internal crane

5 low 50

medium 60

Replacement large parts (< 100 MT) large external crane

6

medium/high 80

high 90

medium/high 80

very high 100

Table 8 Maintenance Categories Repair Costs

69

Table 9 is an example of the excel sheet where these calculations were made. It can be also seen on the Appendix A.

Table 9 Maintenance Activities Cost Analysis

Once the total cost of these activities has been derived, a comparison between the amount of money needed and the number of

times those activities will probably be carried out, was made. Next section is focused on the analysis of these two studies’ results.

Nr Cost (USD/activity) Type% of System's

cost

2 3 1500 4 consumables 30 12.6 12.379 0 500 0 0.7113 3 3000 8 consumables 40 16.6 16.308 0 500 0 0.948

3 3000 8 low 60 22.6 22.203 0 500 0 1.4193 6000 16 low 60 30.6 30.062 0 500 0 1.4304 8000 16 medium 70 30.6 30.062 0 500 0 1.6644 12000 24 medium 70 38.6 37.922 0 500 0 1.6764 12000 24 high 90 38.6 37.922 0 500 0 2.1403 3000 8 low 60 22.6 22.203 0 500 0 1.4193 6000 16 low 60 30.6 30.062 0 500 0 1.4304 8000 16 medium 70 30.6 30.062 0 500 0 1.6644 12000 24 medium 70 38.6 37.922 0 500 0 1.6764 12000 24 high 90 38.6 37.922 0 500 0 2.1406 18000 24 medium/high 80 744 730.928 440000 500 310000 3.3576 18000 24 high 90 744 730.928 440000 500 310000 3.5896 30000 40 medium/high 80 760 746.647 440000 500 310000 3.3846 30000 40 very high 100 760 746.647 440000 500 310000 3.8496 18000 24 medium/high 80 744 730.928 440000 500 310000 3.3576 18000 24 high 90 744 730.928 440000 500 310000 3.5896 30000 40 medium/high 80 760 746.647 440000 500 310000 3.3846 30000 40 very high 100 760 746.647 440000 500 310000 3.849

Total cost

(mUSD)Repair time

(hr)

CrewSubsystem Nr

Description

System Cost

(mUSD)Costs

4

4

6

6

Rotor System

Total Downtime

hrCost

(kUSD)

2.322

Additional cost

equipment during

traveling (USD/trip)

Equipment Cost (USD)

Cost Equipment for

MOB/DEMOB

(USD/mission)

71

4.6 Sensitivity Analysis

4.6.1 Introduction

A Sensitivity Study was carried out to visualize the effect that an increase or

decrease in the principal subsystems’ failure frequencies would suppose for the total

number of failures that a particular subsystem has along its service and extended

life. Therefore, a 10% of deviation has been supposed in this report. However, for

further studies this percentage can be easily changed on the excel sheet.

A failure frequencies’ sensitivity study has been carried out for the Pitch and Yaw

Systems, the Generator and the Drive train. Besides, a sensitivity analysis of the

cost of the Turbine Control and Protection System has also been carried out due to

the fact that no cost breakdown was found for it and the variation of its cost as a

percentage of the total WT cost needs to be investigated to determine whether its

maintenance activities are relevant for the system or not.

4.6.2 Methodology

For every sensitivity analysis, two new tables on a separate Excel sheet have been

created, for the calculation of the accumulated failure frequency at 20 and 30 year

including the increase and decrease in the failure frequency percentage previously

established. On these tables the accumulated failure frequencies have been

calculated in the same way that in the failure frequency study but starting from

different failure frequency values (10 % higher or lower).

The old values, calculated on the failure frequency study, have been included next to

the new ones in order to be able to make a comparison between them and evaluate

the influence that a 10% change on the failure frequencies produce after 20 and 30

years. The table below has been included here as an example of the process that

have just been explained, however results can be seen on the following chapter.

72

Table 10 Pitch System's Sensitivity Analysis

73

For the Turbine control and protection system, the sensitivity analysis has been performed in a different way, by changing the

percentage that this subsystem represents of the overall WT cost. Therefore, the cost of this subsystem’s maintenance activities

can be related to the number of failures that it might have thorough its service and extended life. Table 11 illustrates this study.

Table 11 Turbine Control & Protection System's Sensitivity Analysis

75

5 Results and Discussion

5.1 Failure frequency study

5.1.1 Results

Within this section results tables of the failure frequency study (Table 12 and 13) are

showed. As it was explained on the previous chapter, the Accumulated Failure

Frequency for each maintenance category of every subsystem has been calculated.

On the tables below it can be observed that some cells are coloured in orange in

order to appreciate when the failure frequency increase on unit. It is also noticeable

that maintenance categories number four, five and six have lower failure

frequencies, which is natural because these categories have greater severity that the

others and therefore, higher associated costs. For that reason, some subsystems

were identified as critical due to the high failure frequencies that some of their

Maintenance Categories number four, five and six present. Those subsystems are:

Drive Train, Pitch and Yaw System, and Generator.

It is also important to explain why some subsystems coloured in red were discarded

for posterior analysis. This is due to the fact that firstly, no cost of those subsystems

was found and secondly, the accumulated failure frequencies were low enough to

assume these subsystems will not represent a threat to the overall system and

therefore could be discarded. This is not the case of the “Turbine Control and

Protection System”, which cost was assumed to be a 0.1% of the total WT cost due

to the fact that its failure frequency is relevant and therefore, a sensitivity study of

this subsystem’s cost was performed on a posterior analysis.

To conclude it must be pointed out that the values of “Failure Frequency”,

“Maintenance Category” and “Probability of Occurrence of each Maintenance

Category” have been written in red as they represent inputs and therefore they can

be changed at any time in order to perform again the study with different values, so

this Excel file could become an analysis tool for this sector companies.

77

Subsystem Annual Failure Freq.

Maint. Cat.

Occurr. Prob.

Maint. Cat. (%)

Annual Failure Freq.

Maint. Cat.

Accumulated failure frequency for each maintenance category

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Ro

tor

Syst

em

2 52.5 0.069 0.069 0.137 0.206 0.274 0.343 0.412 0.480 0.549 0.618 0.686 0.755 0.823 0.892 0.961 1.029 1.098 1.166 1.235 1.304 1.372

3 5.0 0.007 0.007 0.013 0.020 0.026 0.033 0.039 0.046 0.052 0.059 0.065 0.072 0.078 0.085 0.091 0.098 0.105 0.111 0.118 0.124 0.131

4 15.0 0.020 0.020 0.039 0.059 0.078 0.098 0.118 0.137 0.157 0.176 0.196 0.216 0.235 0.255 0.274 0.294 0.314 0.333 0.353 0.372 0.392

0.131 4 20.0 0.026 0.026 0.052 0.078 0.105 0.131 0.157 0.183 0.209 0.235 0.261 0.288 0.314 0.340 0.366 0.392 0.418 0.444 0.471 0.497 0.523

6 5.0 0.007 0.007 0.013 0.020 0.026 0.033 0.039 0.046 0.052 0.059 0.065 0.072 0.078 0.085 0.091 0.098 0.105 0.111 0.118 0.124 0.131

6 2.5 0.003 0.003 0.007 0.010 0.013 0.016 0.020 0.023 0.026 0.029 0.033 0.036 0.039 0.042 0.046 0.049 0.052 0.056 0.059 0.062 0.065

Bla

de

Ad

just

me

nt

2 65.0 0.636 0.636 1.271 1.907 2.542 3.178 3.813 4.449 5.085 5.720 6.356 6.991 7.627 8.262 8.898 9.534 10.169 10.805 11.440 12.076 12.711

4 10.0 0.098 0.098 0.196 0.293 0.391 0.489 0.587 0.684 0.782 0.880 0.978 1.076 1.173 1.271 1.369 1.467 1.564 1.662 1.760 1.858 1.956

0.978 5 20.0 0.196 0.196 0.391 0.587 0.782 0.978 1.173 1.369 1.564 1.760 1.956 2.151 2.347 2.542 2.738 2.933 3.129 3.325 3.520 3.716 3.911

6 5.0 0.049 0.049 0.098 0.147 0.196 0.244 0.293 0.342 0.391 0.440 0.489 0.538 0.587 0.636 0.684 0.733 0.782 0.831 0.880 0.929 0.978

Hydraulic System

2 60.0 0.032 0.032 0.064 0.096 0.129 0.161 0.193 0.225 0.257 0.289 0.322 0.354 0.386 0.418 0.450 0.482 0.515 0.547 0.579 0.611 0.643

0.054 4 40.0 0.021 0.021 0.043 0.064 0.086 0.107 0.129 0.150 0.172 0.193 0.214 0.236 0.257 0.279 0.300 0.322 0.343 0.364 0.386 0.407 0.429

Dri

ve T

rain

2 45.0 0.130 0.130 0.260 0.390 0.520 0.650 0.780 0.910 1.040 1.170 1.300 1.430 1.560 1.689 1.819 1.949 2.079 2.209 2.339 2.469 2.599

0.289 4 45.0 0.130 0.130 0.260 0.390 0.520 0.650 0.780 0.910 1.040 1.170 1.300 1.430 1.560 1.689 1.819 1.949 2.079 2.209 2.339 2.469 2.599

6 10.0 0.029 0.029 0.058 0.087 0.116 0.144 0.173 0.202 0.231 0.260 0.289 0.318 0.347 0.375 0.404 0.433 0.462 0.491 0.520 0.549 0.578

Yaw

Sys

tem

2 45.0 0.228 0.228 0.457 0.685 0.914 1.142 1.371 1.599 1.827 2.056 2.284 2.513 2.741 2.969 3.198 3.426 3.655 3.883 4.112 4.340 4.568

0.508 5 45.0 0.228 0.228 0.457 0.685 0.914 1.142 1.371 1.599 1.827 2.056 2.284 2.513 2.741 2.969 3.198 3.426 3.655 3.883 4.112 4.340 4.568

6 10.0 0.051 0.051 0.102 0.152 0.203 0.254 0.305 0.355 0.406 0.457 0.508 0.558 0.609 0.660 0.711 0.761 0.812 0.863 0.914 0.964 1.015

78

Generator

2 45.0 0.146 0.146 0.292 0.438 0.584 0.730 0.876 1.022 1.169 1.315 1.461 1.607 1.753 1.899 2.045 2.191 2.337 2.483 2.629 2.775 2.921

0.325 4 45.0 0.146 0.146 0.292 0.438 0.584 0.730 0.876 1.022 1.169 1.315 1.461 1.607 1.753 1.899 2.045 2.191 2.337 2.483 2.629 2.775 2.921

6 10.0 0.032 0.032 0.065 0.097 0.130 0.162 0.195 0.227 0.260 0.292 0.325 0.357 0.390 0.422 0.454 0.487 0.519 0.552 0.584 0.617 0.649

Control and

protection system

(generator)

2 45.0 0.270 0.270 0.540 0.810 1.080 1.350 1.620 1.890 2.160 2.430 2.700 2.970 3.241 3.511 3.781 4.051 4.321 4.591 4.861 5.131 5.401

0.600 4 45.0 0.270 0.270 0.540 0.810 1.080 1.350 1.620 1.890 2.160 2.430 2.700 2.970 3.241 3.511 3.781 4.051 4.321 4.591 4.861 5.131 5.401

4 10.0 0.060 0.060 0.120 0.180 0.240 0.300 0.360 0.420 0.480 0.540 0.600 0.660 0.720 0.780 0.840 0.900 0.960 1.020 1.080 1.140 1.200

Generator Lead/

transmiss. cables

2 55.0 0.256 0.256 0.512 0.767 1.023 1.279 1.535 1.791 2.046 2.302 2.558 2.814 3.070 3.325 3.581 3.837 4.093 4.349 4.604 4.860 5.116

0.465 4 45.0 0.209 0.209 0.419 0.628 0.837 1.046 1.256 1.465 1.674 1.884 2.093 2.302 2.512 2.721 2.930 3.139 3.349 3.558 3.767 3.977 4.186

Tran

sfo

rmer

2 45.0 0.036 0.036 0.072 0.107 0.143 0.179 0.215 0.250 0.286 0.322 0.358 0.394 0.429 0.465 0.501 0.537 0.572 0.608 0.644 0.680 0.716

0.080 4 45.0 0.036 0.036 0.072 0.107 0.143 0.179 0.215 0.250 0.286 0.322 0.358 0.394 0.429 0.465 0.501 0.537 0.572 0.608 0.644 0.680 0.716

4 10.0 0.008 0.008 0.016 0.024 0.032 0.040 0.048 0.056 0.064 0.072 0.080 0.087 0.095 0.103 0.111 0.119 0.127 0.135 0.143 0.151 0.159

Mac

hin

ery

Encl

osu

re

0.014 2 40.0 0.006 0.006 0.011 0.017 0.022 0.028 0.033 0.039 0.044 0.050 0.055 0.061 0.066 0.072 0.077 0.083 0.088 0.094 0.099 0.105 0.110

4 60.0 0.008 0.008 0.017 0.025 0.033 0.041 0.050 0.058 0.066 0.075 0.083 0.091 0.099 0.108 0.116 0.124 0.132 0.141 0.149 0.157 0.166

Tow

er

2 55.0 0.083 0.083 0.166 0.249 0.333 0.416 0.499 0.582 0.665 0.748 0.832 0.915 0.998 1.081 1.164 1.247 1.331 1.414 1.497 1.580 1.663

4 30.0 0.045 0.045 0.091 0.136 0.181 0.227 0.272 0.318 0.363 0.408 0.454 0.499 0.544 0.590 0.635 0.680 0.726 0.771 0.816 0.862 0.907

0.151 4 10.0 0.015 0.015 0.030 0.045 0.060 0.076 0.091 0.106 0.121 0.136 0.151 0.166 0.181 0.197 0.212 0.227 0.242 0.257 0.272 0.287 0.302

6 5.0 0.008 0.008 0.015 0.023 0.030 0.038 0.045 0.053 0.060 0.068 0.076 0.083 0.091 0.098 0.106 0.113 0.121 0.129 0.136 0.144 0.151

Heating, ventilation,

air conditionin

g

0.014 2 50.0 0.007 0.007 0.014 0.021 0.028 0.035 0.042 0.049 0.056 0.063 0.070 0.077 0.084 0.091 0.098 0.105 0.112 0.119 0.126 0.133 0.140

4 50.0 0.007 0.007 0.014 0.021 0.028 0.035 0.042 0.049 0.056 0.063 0.070 0.077 0.084 0.091 0.098 0.105 0.112 0.119 0.126 0.133 0.140

79

Crane system

0.014 2 50.0 0.007 0.007 0.014 0.022 0.029 0.036 0.043 0.050 0.058 0.065 0.072 0.079 0.086 0.094 0.101 0.108 0.115 0.122 0.130 0.137 0.144

4 50.0 0.007 0.007 0.014 0.022 0.029 0.036 0.043 0.050 0.058 0.065 0.072 0.079 0.086 0.094 0.101 0.108 0.115 0.122 0.130 0.137 0.144

Elevator System

0.006 5 100.0 0.006 0.006 0.011 0.017 0.022 0.028 0.033 0.039 0.044 0.050 0.055 0.061 0.066 0.072 0.077 0.083 0.088 0.094 0.099 0.105 0.110

Lightning protection /grounding

0.012 2 100.0 0.012 0.012 0.024 0.035 0.047 0.059 0.071 0.083 0.094 0.106 0.118 0.130 0.142 0.153 0.165 0.177 0.189 0.201 0.212 0.224 0.236

Turbine control &

protection system

0.862 2 55.0 0.474 0.474 0.948 1.422 1.896 2.369 2.843 3.317 3.791 4.265 4.739 5.213 5.687 6.160 6.634 7.108 7.582 8.056 8.530 9.004 9.478

4 45.0 0.388 0.388 0.775 1.163 1.551 1.939 2.326 2.714 3.102 3.489 3.877 4.265 4.653 5.040 5.428 5.816 6.204 6.591 6.979 7.367 7.754

Windfarm Cables

0.050 4 100.0 0.050 0.050 0.100 0.150 0.200 0.250 0.300 0.350 0.400 0.450 0.500 0.550 0.600 0.650 0.700 0.750 0.800 0.850 0.900 0.950 1.000

Table 12: Servive Life Accumulated Failure Frequency for each Maintenance Category of every Subsystem

80

Subsystem Annual Failure

Frequency

Maintenance category

Probability of

occurrence Mainten. Cat. (%)

Annual Failure

Frequency Maintenance

Cat.

Life Extension Accumulated Failure Frequencies

21 22 23 24 25 26 27 28 29 30

Rotor System

2 52.5 0.069 1.441 1.510 1.578 1.647 1.715 1.784 1.853 1.921 1.990 2.059

3 5.0 0.007 0.137 0.144 0.150 0.157 0.163 0.170 0.176 0.183 0.190 0.196

4 15.0 0.020 0.412 0.431 0.451 0.471 0.490 0.510 0.529 0.549 0.569 0.588

0.131 4 20.0 0.026 0.549 0.575 0.601 0.627 0.654 0.680 0.706 0.732 0.758 0.784

6 5.0 0.007 0.137 0.144 0.150 0.157 0.163 0.170 0.176 0.183 0.190 0.196

6 2.5 0.003 0.069 0.072 0.075 0.078 0.082 0.085 0.088 0.091 0.095 0.098

Blade Adjustment

2 65.0 0.636 13.347 13.983 14.618 15.254 15.889 16.525 17.160 17.796 18.432 19.067

4 10.0 0.098 2.053 2.151 2.249 2.347 2.445 2.542 2.640 2.738 2.836 2.933

0.978 5 20.0 0.196 4.107 4.302 4.498 4.693 4.889 5.085 5.280 5.476 5.671 5.867

6 5.0 0.049 1.027 1.076 1.124 1.173 1.222 1.271 1.320 1.369 1.418 1.467

Hydraulic System

2 60.0 0.032 0.675 0.708 0.740 0.772 0.804 0.836 0.868 0.900 0.933 0.965

0.054 4 40.0 0.021 0.450 0.472 0.493 0.515 0.536 0.557 0.579 0.600 0.622 0.643

Drive Train

2 45.0 0.130 2.729 2.859 2.989 3.119 3.249 3.379 3.509 3.639 3.769 3.899

0.289 4 45.0 0.130 2.729 2.859 2.989 3.119 3.249 3.379 3.509 3.639 3.769 3.899

6 10.0 0.029 0.606 0.635 0.664 0.693 0.722 0.751 0.780 0.809 0.838 0.866

Yaw System

2 45.0 0.228 4.797 5.025 5.254 5.482 5.711 5.939 6.167 6.396 6.624 6.853

0.508 5 45.0 0.228 4.797 5.025 5.254 5.482 5.711 5.939 6.167 6.396 6.624 6.853

6 10.0 0.051 1.066 1.117 1.167 1.218 1.269 1.320 1.371 1.421 1.472 1.523

81

Generator

2 45.0 0.146 3.067 3.214 3.360 3.506 3.652 3.798 3.944 4.090 4.236 4.382

0.325 4 45.0 0.146 3.067 3.214 3.360 3.506 3.652 3.798 3.944 4.090 4.236 4.382

6 10.0 0.032 0.682 0.714 0.747 0.779 0.812 0.844 0.876 0.909 0.941 0.974

Control and protection

system (generator)

2 45.0 0.270 5.671 5.941 6.211 6.481 6.751 7.021 7.291 7.561 7.831 8.101

0.600 4 45.0 0.270 5.671 5.941 6.211 6.481 6.751 7.021 7.291 7.561 7.831 8.101

4 10.0 0.060 1.260 1.320 1.380 1.440 1.500 1.560 1.620 1.680 1.740 1.800

Generator Lead/

transmission cables

2 55.0 0.256 5.372 5.628 5.884 6.139 6.395 6.651 6.907 7.163 7.418 7.674

0.465 4 45.0 0.209 4.395 4.604 4.814 5.023 5.232 5.442 5.651 5.860 6.070 6.279

Transformer

2 45.0 0.036 0.751 0.787 0.823 0.859 0.894 0.930 0.966 1.002 1.037 1.073

0.080 4 45.0 0.036 0.751 0.787 0.823 0.859 0.894 0.930 0.966 1.002 1.037 1.073

4 10.0 0.008 0.167 0.175 0.183 0.191 0.199 0.207 0.215 0.223 0.231 0.239

Machinery Enclosure

0.014 2 40.0 0.006 0.116 0.121 0.127 0.132 0.138 0.144 0.149 0.155 0.160 0.166

4 60.0 0.008 0.174 0.182 0.190 0.199 0.207 0.215 0.224 0.232 0.240 0.248

Tower

2 55.0 0.083 1.746 1.830 1.913 1.996 2.079 2.162 2.245 2.328 2.412 2.495

4 30.0 0.045 0.953 0.998 1.043 1.089 1.134 1.179 1.225 1.270 1.315 1.361

0.151 4 10.0 0.015 0.318 0.333 0.348 0.363 0.378 0.393 0.408 0.423 0.438 0.454

6 5.0 0.008 0.159 0.166 0.174 0.181 0.189 0.197 0.204 0.212 0.219 0.227

Heating, ventilation, air conditioning

0.014

2 50.0 0.007 0.147 0.154 0.161 0.168 0.175 0.182 0.189 0.196 0.203 0.210

4 50.0 0.007 0.147 0.154 0.161 0.168 0.175 0.182 0.189 0.196 0.203 0.210

82

Crane system 0.014

2 50.0 0.007 0.151 0.158 0.166 0.173 0.180 0.187 0.194 0.202 0.209 0.216

4 50.0 0.007 0.151 0.158 0.166 0.173 0.180 0.187 0.194 0.202 0.209 0.216

Elevator System

0.006 5 100.0 0.006 0.116 0.121 0.127 0.132 0.138 0.143 0.149 0.154 0.160 0.165

Lightning protection /grounding

0.012 2 100.0 0.012 0.248 0.260 0.271 0.283 0.295 0.307 0.319 0.330 0.342 0.354

Turbine control & protection

system

0.862 2 55.0 0.474 9.951 10.425 10.899 11.373 11.847 12.321 12.795 13.269 13.743 14.216

4 45.0 0.388 8.142 8.530 8.918 9.305 9.693 10.081 10.468 10.856 11.244 11.632

Windfarm Cables

0.050 4 100.0 0.050 1.050 1.100 1.150 1.200 1.250 1.300 1.350 1.400 1.450 1.500

Table 13: Life Extension Accumulated Failure Frequency for each Maintenance Category of every Subsystem

83

5.1.2 Conclusions and Recommendations

After the observation of the different subsystems’ failure frequencies and its

prioritization, it can be concluded that this analysis shows the necessity of

performing an assessment of the Maintenance Activities Cost in order to determine

which subsystems will need further design improvements or their performance along

the years will simply improve by managing their maintenance activities better.

Besides, after the analysis of this study, it has been concluded that the investigation

of the Failure Frequencies rate of change along the service life and life extension of

WTs subsystems would be really interesting as it is believed that those failure

frequencies for most of the subsystems will behave following the bathtub curve

(Figure 5). This curve shows how at the end of life of a WT its failure intensity

increases. Therefore, this study results are limited by the assumption that the failure

frequency is cumulative. On the following chapter the further study related with this

topic and considered necessary has been better explained.

5.2 Maintenance activities Cost Analysis

5.2.1 Results

On the “Maintenance Activities Cost Analysis” performed in the previous chapter, a

comparison between the total amount of money maintenance activities need

depending, not only on the subsystem’s cost but also on the severity of the failure

(the category) and the frequency that (approximately) these maintenance activities

were performed along the service life and a life extension period of 10 years, was

made.

On Appendix A.2 this study’s results have been recorded for every WT subsystem.

However, some subsystems were identified as “critical” for the system’s reliability

and profitability; therefore their results have been included in this section. Below

these lines, in Table 14, the cost of the critical subsystems is associated with its

failure frequency at year 20 and 30 is shown. Those critical subsystems are: Pitch

and Yaw System, Generator and Drive train.

84

Table 14 Critical subsystems' Maintenance Costs and Failure Frequency comparison

2 0.093 12.711 19.067

0.183

0.194

0.222

0.234

0.286

0.145

0.184

1.709

1.735

1.737

1.789

2 0.093 0.643 0.965

0.183

0.194

0.222

0.234

0.286

2 0.571 2.599 3.899

1.139

1.150

1.338

1.349

1.721

2.984

3.170

3.012

3.383

2 0.051 4.568 6.853

0.075

0.101

1.598

1.610

1.626

1.650

2 0.116 2.921 4.382

0.229

0.240

0.276

0.288

0.355

1.771

1.804

1.798

1.866

2 0.116 5.401 8.101

0.229

0.240

0.276

0.288

0.355

0.229

0.240

0.276

0.288

0.355

2 0.116 5.116 7.674

0.229

0.240

0.276

0.288

0.355

Maintennace

Category

Accumulated

Failure

Frequency

(20years)

Accumulated

Failure

Frequency

(30years)

Bla

de

Ad

just

me

nt

Hyd

rau

lic

Syst

em

Ya

w S

yste

mC

on

tro

l a

nd

pro

tect

ion

syst

em

(g

en

era

tor)

4 1.956 2.933

5 3.911 5.867

6 0.978 1.467

4 0.429 0.643

Dri

ve T

rain 4 2.599 3.899

6 0.578 0.866

5 4.568 6.853

6 1.015 1.523

Ge

ne

rato

r

4 2.921 4.382

6 0.649 0.974

4 5.401 8.101

4 1.200 1.800

Ge

ne

rato

r

Lea

d/

tra

nsm

issi

on

cab

les

4 4.186 6.279

SubsystemTotal cost

(mUSD)

85

As it can be appreciated, costs increase considerably when a Large Part

replacement (maintenance category 6) has to be carried out, especially for the Drive

Train. This is due to the high downtime this activity presents as maintenance labours

cannot be started until the jack-up arrives the offshore emplacement.

Maintenance category six for Blade Adjustment, Yaw system and Generator present

costs about a million and a half USD dollars per activity and also similar failure

frequencies at the end of the service life and the life extension. However, the same

maintenance activity for the Drive Train will carry much higher costs (about 3 million)

while its failure frequency is a bit lower than others category six’s failure frequencies,

but the reduction does not compensate the much higher costs this failure imply.

Moreover, Drive Train Small Parts Replacements Costs (category 4), and its failure

frequency are particularly high, which may carry important quantities of money along

the years. Therefore, special attention must be paid to the Drive Train Subsystem

and particular effort must be made on this subsystem’s faults diagnosis and

prognosis.

There are another two subsystems in the same situation that the Drive Train,

however, this time is for maintenance category number 4 (Small Parts

Replacement). These subsystems are the Generator lead/transmission cables and

the Generator’s Control and protection system. As it can be appreciated in Table14,

even these subsystems costs are similar than other category four costs, their failure

frequencies are considerably high, potentially representing economical issues.

Moreover, the Small Parts Replacement of the Drive Train constitutes the most

critical maintenance activity due to its high costs which represent an economical

threat.

5.2.2 Conclusions and Recommendations

After the explanation of the previous section it can be concluded that the two critical

maintenance categories, which are the replacement of both, small and large parts,

have a heavy impact on the O&M costs. However, each one of them influences the

system in a different way. While Category number 4 has an impact over the system

due to its high failure frequency, Category number 6’s impact is caused due to the

great costs this activity carries.

86

Therefore, it is recommended to re-elaborate the maintenance plan in order to

determine whether these cost and the magnitude of their impact over the system can

be reduced.

Two easy methods are suggested for that purpose: the first one consists on

increasing the number of “Preventive Small Parts Replacements” (Maintenance

Category 5) while the second one consists on creating another Maintenance

Category (number 7) where the “Preventive Large Parts Replacements” is

performed.

Looking at maintenance categories number 4 of Table12 and 13 and their failure

rates over 30 years it can be appreciated that, during the Drive Train’s service life,

Preventive Small Parts Replacement (Category 5) can be scheduled at least twice

instead of waiting its failure. Moreover, this procedure can be repeated another two

times during the life extension period. The generator is another subsystem that might

take advantage of this method by scheduling preventive replacement of some of its

small parts between two and three times during the service life and another one

during the life extension.

The second method was created with the aim of anticipating large parts failure and

saving money reducing the high downtime this kind of faults produce. Therefore,

looking the accumulated failure frequencies table (Excel file) it was appreciated the

necessity of schedule this new maintenance activity for some subsystems: once for

the Blade Adjustment, between years 18th and 20th (considering the life extension a

fact); once for the Yaw System, between years 16th and 19th; once for the Generator

between years 25th and 27th and finally another one for the Drive Train during the last

years of the life extension. A further description of Maintenance Category number 7

and its characteristics can be found on the Appendix A.3.

Table 16 shows the costs calculation of these two methods implementation, for the

cases stated above and the amount of money that is saved each time, are

performed. As it can be seen, important savings are made, therefore the application

of these methods for further maintenance plans is highly recommended.

87

Sub

syst

em

Nr

Description

System Cost

(mUSD)

Total Downtime Equipment Cost (USD)

Total cost

(mUSD)

Accumulated Failure

Frequency (20years)

Accumulated Failure

Frequency (30years)

Crew

Repair time (hr)

Repair Costs

hr Cost

(kUSD)

Cost Equipment for MOB/ DEMOB (USD/

mission)

Additional cost equipment during

travelling (USD/trip)

Nr Cost

(USD/ activity)

Type % of

System's cost

Bla

de

Ad

just

me

nt

2 3 1500 4 consumables 30

0.262

12.6 12.379 0 500 0 0.093 12.711 19.067

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.183

1.956 2.933

3 6000 16 low 60 30.6 30.062 0 500 0 0.194

4 8000 16 medium 70 30.6 30.062 0 500 0 0.222

4 12000 24 medium 70 38.6 37.922 0 500 0 0.234

4 12000 24 high 90 38.6 37.922 0 500 0 0.286

5 3 3000 8 low 50 10.6 10.414 0 500 0 0.145

3.911 5.867

4 8000 16 medium 60 18.6 18.273 0 500 0 0.184

6

6 18000 24 medium/high 80 744.0 730.928 440000 500 310000 1.709

0.978 1.467 Savings (mUSD) (Cat.6 costs - Cat.7 costs)

6 18000 24 high 90 744.0 730.928 440000 500 310000 1.735

6 30000 40 medium/high 80 760.0 746.647 440000 500 310000 1.737

6 30000 40 very high 100 760.0 746.647 440000 500 310000 1.789

7 6 18000 24 high 80 26.6 26.133 440000 500 310000 1.004

- - 0.725 6 18000 24 very high 90 26.6 26.133 440000 500 310000 1.030

88

Hyd

rau

lic S

yste

m

2 3 1500 4 consumables 30 12.6 12.379 0 500 0 0.093 0.643 0.965

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.183

0.429 0.643

3 6000 16 low 60 30.6 30.062 0 500 0 0.194

4 8000 16 medium 70 30.6 30.062 0 500 0 0.222

4 12000 24 medium 70 38.6 37.922 0 500 0 0.234

4 12000 24 high 90 38.6 37.922 0 500 0 0.286

Dri

ve T

rain

2 3 1500 4 consumables 30

1.856

12.6 12.379 0 500 0 0.571 2.599 3.899

4

3 3000 8 low 60 22.6 22.203 0 500 0 1.139

2.599 3.899

3 6000 16 low 60 30.6 30.062 0 500 0 1.150

Savings (mUSD) (Cat.4 costs - Cat.5 costs)

4 8000 16 medium 70 30.6 30.062 0 500 0 1.338

4 12000 24 medium 70 38.6 37.922 0 500 0 1.349

4 12000 24 high 90 38.6 37.922 0 500 0 1.721

5 3 3000 8 low 50 10.6 10.414 0 500 0 0.942

- - 0.298 4 8000 16 medium 60 18.6 18.273 0 500 0 1.140

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 2.984

0.578 0.866 Savings (mUSD)

(Cat.6 costs - Cat.7 costs)

6 18000 24 high 90 744 730.928 440000 500 310000 3.170

6 30000 40 medium/high 80 760 746.647 440000 500 310000 3.012

6 30000 40 very high 100 760 746.647 440000 500 310000 3.383

7 6 18000 24 high 80 26.6 26.133 440000 500 310000 2.279

- - 0.765 6 18000 24 very high 90 26.6 26.133 440000 500 310000 2.465

89

Yaw

Sys

tem

2 3 1500 4 consumables 30

0.123

12.6 12.379 0 500 0 0.051 4.568 6.853

5

3 3000 8 low 50 10.6 10.414 0 500 0 0.075 4.568 6.853

4 8000 16 medium 60 18.6 18.273 0 500 0 0.101

6

6 18000 24 medium/high 80 744.0 730.928 440000 500 310000 1.598

1.015 1.523 Savings (mUSD)

(Cat.6 costs - Cat.7 costs)

6 18000 24 high 90 744.0 730.928 440000 500 310000 1.610

6 30000 40 medium/high 80 760.0 746.647 440000 500 310000 1.626

6 30000 40 very high 100 760.0 746.647 440000 500 310000 1.650

7 6 18000 24 high 80 26.6 26.133 440000 500 310000 0.893

- - 0.722 6 18000 24 very high 90 26.6 26.133 440000 500 310000 0.905

Gen

era

tor

2 3 1500 4 consumables 30

0.339

12.6 12.379 0 500 0 0.116 2.921 4.382

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.229

2.921 4.382

3 6000 16 low 60 30.6 30.062 0 500 0 0.240

Savings (mUSD) (Cat.4 costs - Cat.5 costs)

4 8000 16 medium 70 30.6 30.062 0 500 0 0.276

4 12000 24 medium 70 38.6 37.922 0 500 0 0.288

4 12000 24 high 90 38.6 37.922 0 500 0 0.355

5 3 3000 8 low 50 10.6 10.414 0 500 0 0.183

- - 0.071 4 8000 16 medium 60 18.6 18.273 0 500 0 0.230

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 1.771

0.649 0.974 Savings (mUSD)

(Cat.6 costs - Cat.7 costs)

6 18000 24 high 90 744 730.928 440000 500 310000 1.804

6 30000 40 medium/high 80 760 746.647 440000 500 310000 1.798

6 30000 40 very high 100 760 746.647 440000 500 310000 1.866

7 6 18000 24 high 80 26.6 26.133 440000 500 310000 1.066

- - 0.727 6 18000 24 very high 90 26.6 26.133 440000 500 310000 1.100

Table 15: Recommended changes on maintenance activities and their associated savings

91

5.3 Sensitivity Analysis

5.3.1 Introduction

Within this section Sensitivity Study results have been displayed. During the

following ones, the effect that an increase or decrease in the principal subsystems’

failure frequencies would suppose to the total number of failures that a particular

subsystem has along its service and extended life, can be visualized. In addition how

the system may be affected has been also assessed. Therefore, a 10% of deviation

has been supposed for every case.

5.3.2 Pitch System Sensitivity Analysis results, conclusions and

recommendations

As it can be appreciated, notable changes are made in the Blade Adjustment with

both, the increase and decrease in the failure frequency due to the considerably high

values categories 4 and 5 present and the extremely high value of category 2. The

most interesting conclusion that can be made by observing these failure frequencies

is that the reduction of these categories failure frequencies will carry substantial

economic savings due to the reduction of the amount of times these maintenance

activities have to be carried out. Therefore, an improvement on this subsystem’s

reliability is recommended, not only by improving its design, but also by researching

on new CM methods.

Incr

ease

on

th

e Fa

ilure

Fre

qu

ency

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Blade Adjustment

2 0.093 0.636

10

13.983 12.711 20.974 19.067

4

0.183

0.098 2.151 1.956 3.227 2.933

0.194

0.222

0.234

0.286

5 0.145

0.196 4.302 3.911 6.453 5.867 0.184

6

1.709

0.049 1.076 0.978 1.613 1.467 1.735

1.737

1.789

92

Hydraulic System

2 0.093 0.032 0.708 0.643 1.061 0.965

4

0.183

0.021 0.472 0.429 0.708 0.643

0.194

0.222

0.234

0.286

Table 16: Increase on Pitch System's Failure Frequencies

Dec

reas

e o

n t

he

Failu

re F

req

uen

cy

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Blade Adjustment

2 0.093 0.636

10

11.440 12.711 17.160 19.067

4

0.183

0.098 1.760 1.956 2.640 2.933

0.194

0.222

0.234

0.286

5 0.145

0.196 3.520 3.911 5.280 5.867 0.184

6

1.709

0.049 0.880 0.978 1.320 1.467 1.735

1.737

1.789

Hydraulic System

2 0.093 0.032 0.579 0.643 0.868 0.965

4

0.183

0.021 0.386 0.429 0.579 0.643

0.194

0.222

0.234

0.286

Table 17: Decrease on Pitch System's Failure Frequencies

5.3.3 Drive train Sensitivity Analysis results, conclusions and

recommendations

Within the Drive Train, it can be appreciated than an increase in the failure frequency

during the service life will probably imply an increase in the maintenance activities

and therefore an increase in these costs. However this increase does not suppose

special changes on the maintenance activities during the life extension due to the

fact that the failure frequency is already relatively high without the change.

93

Moreover, a decrease in the failure frequency during the life extension will probably

imply a decrease in all maintenance activities, including category 6, which represents

a huge improvement in this subsystems performance and will carry considerable

savings to the owner. Therefore, an improvement in this subsystem’s reliability is

highly recommended, not only by improving its design, but also by researching on

new CM methods.

Incr

ease

on

th

e Fa

ilure

Fre

qu

ency

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Drive Train

2 0.571 0.130

10

2.859 2.599 4.289 3.899

4

1.139

0.130 2.859 2.599 4.289 3.899

1.150

1.338

1.349

1.721

6

2.984

0.029 0.635 0.578 0.953 0.866 3.170

3.012

3.383

Table 18: Increase on Drive Train's Failure Frequencies

Dec

reas

e o

n t

he

Failu

re F

req

uen

cy

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Drive Train

2 0.571 0.130

10

2.339 2.599 3.509 3.899

4

1.139

0.130 2.339 2.599 3.509 3.899

1.150

1.338

1.349

1.721

6

2.984

0.029 0.520 0.578 0.780 0.866 3.170

3.012

3.383

Table 19: Decrease on Drive Train's Failure Frequencies

94

5.3.4 Yaw System Sensitivity Analysis results, conclusions and

recommendations

The Yaw System is also highly influenced by the variations on its failure frequencies

due to the fact their experimental values are already considerably high. As it can be

observed in Table 20, the increase in the failure frequency entails notably

detrimental effects to the subsystem during both, the service life and the life

extension, for maintenance categories 2 and 5.

Moreover, the decrease in the failure frequency allows the owner to save some

economic resources on the life extension maintenance activities of the same

categories and on the service life of the large parts replacements which, in case that

the life extension do not represent an option, might not have to be carried out.

Incr

ease

on

th

e Fa

ilure

Freq

uen

cy

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Yaw System

2 0.051 0.228

10

5.025 4.568 7.538 6.853

5 0.075

0.228 5.025 4.568 7.538 6.853 0.101

6

1.598

0.051 1.117 1.015 1.675 1.523 1.610

1.626

1.650

Table 20: Increase on Yaw System's Failure Frequencies

Dec

reas

e o

n t

he

Failu

re

Freq

uen

cy

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Yaw System

2 0.051 0.228

10

4.112 4.568 6.167 6.853

5 0.075

0.228 4.112 4.568 6.167 6.853 0.101

6

1.598

0.051 0.914 1.015 1.371 1.523 1.610

1.626

1.650

Table 21: Decrease on Yaw System's Failure Frequencies

95

5.3.5 Generator Sensitivity Analysis results, conclusions and

recommendations

Within the Generator (subsystem composed by the proper Generator, its control and

protection system and its lead/transmission cables), it can be appreciated than an

increase in the failure frequency during the service life just implies detrimental effects

in the generator’s control and protection system and not entails much more influence

to the other components. However this increase supposes some change in the

maintenance activities during the life extension of almost all categories of the

subsystem (being category number 6 and the generator’s category number 4 with

low failure frequency, the exceptions).

Thus, a decrease in the failure frequency during the life extension decreases the

necessary generator’s control and protection system and lead/transmission cables

amount of maintenance activities. The same procedure implies not only the life

extension improvement already mentioned but also the generator’s service life

improvement, excluding category 6. To conclude, a decrease in the failure

frequencies of this subsystem represent huge improvements on its performance and

will carry considerable savings to the owner. Therefore, further work on its reliability

and CM method is recommended.

Incr

ease

on

th

e Fa

ilure

Fre

qu

ency

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Generator

2 0.116 0.146

10

3.214 2.921 4.820 4.382

4

0.229

0.146 3.214 2.921 4.820 4.382

0.240

0.276

0.288

0.355

6

1.771

0.032 0.714 0.649 1.071 0.974 1.804

1.798

1.866

96

Control and protection

system (generator)

2 0.116 0.270

5.941 5.401 8.911 8.101

4

0.229

0.270 5.941 5.401 8.911 8.101

0.240

0.276

0.288

0.355

4

0.229

0.060 1.320 1.200 1.980 1.800

0.240

0.276

0.288

0.355

Generator Lead/

transmission cables

2 0.116 0.256 5.628 5.116 8.442 7.674

4

0.229

0.209 4.604 4.186 6.907 6.279

0.240

0.276

0.288

0.355

Table 22: Increase on Generator System's Failure Frequencies

Dec

reas

e o

n t

he

Failu

re F

req

uen

cy

Subsystem Maintenance

category Cost

(mUSD) Failure

Frequency % of

change

Year 20 Year 30

With change

Without change

With change

Without change

Generator

2 0.116 0.146

10

2.629 2.921 3.944 4.382

4

0.229

0.146 2.629 2.921 3.944 4.382

0.240

0.276

0.288

0.355

6

1.771

0.032 0.584 0.649 0.876 0.974 1.804

1.798

1.866

97

Control and protection

system (generator)

2 0.116 0.270

4.861 5.401 7.291 8.101

4

0.229

0.270 4.861 5.401 7.291 8.101

0.240

0.276

0.288

0.355

4

0.229

0.060 1.080 1.200 1.620 1.800

0.240

0.276

0.288

0.355

Generator Lead/

transmission cables

2 0.116 0.256 4.604 5.116 6.907 7.674

4

0.229

0.209 3.767 4.186 5.651 6.279

0.240

0.276

0.288

0.355

Table 23: Decrease on Generator System's Failure Frequencies

5.3.6 Turbine Control and Protection System Analysis results,

conclusions and recommendations

A sensitivity analysis of the cost of the Turbine Control and Protection System was

carried out to determine whether its maintenance activities cost is relevant for the

System or not, due to the fact that no cost breakdown was found for this subsystem.

Therefore, its cost was assumed firstly as the 0.1% of the total WT cost and

secondly as the 1%. Table 24 shows the analysis’ results.

As it can be appreciated, the increase of this subsystems cost to the 1%, would

imply that the cost of the maintenance activities will be the double that the ones

performed with the 0.1% of the total cost. Watching the values of these maintenance

activities they seem to be low. However, the high failure frequency this subsystem

present, make the minimization of those values extremely important.

99

Subsystem Maintenance

Category

Description

System Cost

Total Downtime

Equipment Cost (USD)

Total cost

(mUSD)

Accumulated Failure

Frequency (20years)

Accumulated Failure

Frequency (30years)

Crew

Repair time (hr)

Repair Costs

hr Cost

(kUSD)

Cost Equipment for MOB/ DEMOB (USD/mission)

Additional cost

equipment during

travelling (USD/trip)

Nr Cost

(USD/ activity)

Type % of

System's cost

% of total cost

mUSD

Turb

ine

con

tro

l & p

rote

ctio

n

syst

em

2 3 1500 4 consumables 30

0.1 0.010

12.6 12.379 0 500 0 0.017 9.4776 14.2164

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.032

7.7544 11.6316

3 6000 16 low 60 30.6 30.062 0 500 0 0.042

4 8000 16 medium 70 30.6 30.062 0 500 0 0.045

4 12000 24 medium 70 38.6 37.922 0 500 0 0.057

4 12000 24 high 90 38.6 37.922 0 500 0 0.059

2 3 1500 4 consumables 30

1 0.099

12.6 12.379 0 500 0 0.044 9.4776 14.2164

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.085

7.7544 11.6316

3 6000 16 low 60 30.6 30.062 0 500 0 0.096

4 8000 16 medium 70 30.6 30.062 0 500 0 0.108

4 12000 24 medium 70 38.6 37.922 0 500 0 0.119

4 12000 24 high 90 38.6 37.922 0 500 0 0.139

Table 24: Cost Sensitivity Analysis of the Turbine Control and Protection System

101

5.4 Is Repowering a suitable option?

Repowering represents the procedure of either reestablishing existing WTs with new

ones that have larger rate power and efficiency or replacing the turbine while reusing

the tower. Therefore, in the last years of a WF’s operational life, the owner might

decide whether repowering is a profitable option and in which conditions it might be

carried out. This decision should be based on:

The WF’s profitability, as time passes both performance and reliability

decrease.

The profits expectation for both, life extension and the different repowering

options

The benefits ratio that repowering will present against the WF full

decommissioning and project components recycling [17].

There are three different types of repowering that depending on the circumstances of

the actual WT and the owner’s interest would be:

Same tower with a new, lower capacity turbine: this option conjugates a

smaller WT that even has lower capacity and therefore produces less

electricity, needs little maintenance and will last another twenty years; with the

same tower that, having decreased the power of the turbine, will have less

applied forces and moments and therefore, its structural integrity will resist

longer.

Same tower with a new, higher capacity turbine: this option conjugates a

higher WT that will produce more electricity and will last another twenty years;

with the same tower that having increased the power of the turbine will have

greater applied forces and moments and therefore, its structural integrity will

be highly compromised. Therefore, this option usually will not be viable,

unless the structural integrity of the tower will be strong enough to resist the

new requirements. This option will be rarely carried out.

New tower with a new, higher capacity turbine: this option entails the tower

and nacelle decommissioning for the later commissioning of a new WT.

102

Another possibility would be reusing some infrastructure from the WF to reduce the

capital cost of the second one (after repowering). For example, most of the original

subsea cables might be reused, along with the existing grid connection. However, if

the WT capacity has been increased, the grid connection may have to be changed.

In order to decide which alternative is the most profitable an exhaustive multi-criteria

analysis has to be performed with real data. Some of the critical parameters this

study should focus on, are: structural integrity simulations that check the applied

forces and moments and the resistance to fatigue the tower may have, in order to

decide whether the tower would be able to resist the new nacelle or not,

environmental factors, reliability assessments and expectations, economical criteria,

profits expectations, substantial changes on maintenance activities and their new

risk management, among others.

Due to the unavailability of experimental data, this analysis is beyond these thesis

possibilities. However, the topic is highly recommended for a PhD due to the huge

repercussions and interest that will represent for the industry.

5.5 Further considerations

As WFs are evolving, they tend to be located each time farther to the coast. In fact,

the new generation of WFs development, “Round 3”, will suppose a change on the

O&M activities due to the considerable increase on the average onshore-offshore

distance. This phenomenon will carry an increase of most of the identified risks of

section 3.4: “O&M Risk Identification”, especially of the ones related with the low

accessibility to the offshore emplacement due to bad weather conditions, long transit

time and spares logistic time, among others.

However, new tendencies are helping the mitigation of those new threats. For

instance, the low accessibility to the WF due to bad weather conditions can be

mitigated with the use of a helicopter instead that the use of a workboat. Costs are a

bit higher and fewer technicians could be transported each time; however

accessibility will be considerably improved. Moreover, it has to be kept in mind that

even the transit time of these new WFs will be higher and therefore, so will be the

downtime; the greater distance of the WF from the coast will imply most of the times

higher capacity and greater electricity production.

103

Thus, it is also known the necessity of improving spares management and stocking

which could be easily done by the combination of two concepts. The first one is

related to the spares warehouse transfer, from its onshore emplacement to an

offshore one, which could be, for example, an offshore substation. The second idea

is, depending on the WF’s dimensions, have a “pool of big spares” that allows to

change a big part (as the generator) when it is about to fail or has already failed with

one of the pool, instead of repairing it offshore. Therefore both, the spares and

equipment logistic times will be minimized and so do the loss of revenue.

In the same vein, it has to be taken into account that in a very big WF the jack-up

charting frequency might be high enough to consider the possibility of buying one in

order to have it totally available to the WF’s maintenance activities and saving a

huge amount of money on turbines’ downtime; due to the fact that, the time that the

jack-up takes to arrive the offshore emplacement, is the principal cause of downtime

and therefore, the main loss of revenue cause.

Nevertheless, the combination these three ideas (preventive replacements, pool of

spares and own jack-up) may become the maintenance activities’ key to success,

due to the fact that having a jack-up totally available would make possible to

increase the amount of preventive replacement activities. Therefore, these could be

done at the slightest suspicion of a component’s deterioration or failure and

downtime will be considerably decreased. Furthermore, having a pool of spares

would diminish dramatically the spares lead time, contributing to downtime reduction.

Lastly, performing more preventive replacements would imply that the replaced

components will not have catastrophic damages, avoiding being transformed into

useless components but being repaired and returned to the spares pool.

This last combination of ideas is consider very interesting for further WF projects and

therefore its investigation and a cost-benefit analysis, which optimizes the

maintenance activities, is highly recommended for future projects.

105

6 Further Work

Within this chapter, the future work that might be carried out related with this thesis

topic is explained. Due to the fact that the main limitations of the previous carried

work was the high quality and quantity of data needed, further studies must be total

or partially supported by several companies highly related with the sector as could

be certification companies, manufacturers or even WFs owners, among others.

The first recommended study is the Failure Frequency Rate of change Analysis of

the critical WT’s subsystems, in order to investigate its variation along the years.

This analysis is considered relevant, as it is believed that failure frequencies will

increase at the end of the WTs life either following or being related with the bathtub

curve (Figure 5). Moreover, it is believed that not every component will deteriorate in

the same way and also different behaviours are expected among WFs. Therefore, by

the analysis of several WFs and their components, different deterioration tendencies

and the critical phenomena that produce them, as could be the environmental factors

experimented on a particular WF, are expected to be identified. Lastly, the final aim

of this study will be an optimisation of the maintenance plan depending on the WF

age.

Besides, the maintenance plan optimisation might be also carried out not only for a

WT but also for the whole WF, taking into account the new WFs trends and issues

exposed in section 5.5. Introduce new spares storage methods, helicopters as active

maintenance equipment and jack-ups total availability are other possibilities that

should be explored and economically assessed. For all of these analyses a huge

quantity of data is needed, therefore companies’ cooperation is crucial.

Nevertheless, for future work it is highly recommended to perform the tasks

suggested above not only with real high quality data but also with more complex

modelling tools, as could be AnyLogic; a powerful software that has an application

for WT’s maintenance models where several maintenance parameters and cost can

be modelled in different environments. This tool and some tutorials can be seen in

the following link [114]. Although some other software could also be used.

Bearing in mind that the final aim of this project was the maintenance optimisation for

making WTs life extension possible, the last task proposed for further work is to

106

perform a multi-criteria decision tool where, once all the necessary inputs are

introduced, the system prioritizes among all different end of life options, the most

profitable within specified security boundaries. Within end of life options would be

considered: life extension, repowering (in the three configurations explained in

Section 5.4) and decommissioning.

107

109

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117

APPENDICES

Appendix A Cost Analysis Model extended data and

results

A.1 Extended Baseline Data

Figure A-1 WT cost breakdown (5 MW Offshore WT)

Source: [115]

118

Table A-1 Capital Cost structure of Offshore Wind Power Systems (2010)

Source: [116]

Figure A-2 General data from the US WF

Source: [112]

119

A.2 Extended Cost Analysis Results

Subsystem Nr

Description

System Cost

(mUSD)

Total Downtime Equipment Cost (USD)

Total cost

(mUSD)

Accumulated Failure Frequency (20years)

Accumulated

Failure Frequency (30years)

Crew

Repair time (hr)

Repair Costs

hr Cost

(kUSD)

Cost Equipment for MOB/ DEMOB

Additional cost

equipment during

travelling (USD/trip)

Nr Cost

(USD/ activity)

Type % of

System's cost

Rotor System

2 3 1500 4 consumables 30

2.322

12.6 12.379 0 500 0 0.711 1.372 2.059

3 3 3000 8 consumables 40 16.6 16.308 0 500 0 0.948 0.131 0.196

4

3 3000 8 low 60 22.6 22.203 0 500 0 1.419

0.392 0.588

3 6000 16 low 60 30.6 30.062 0 500 0 1.430

4 8000 16 medium 70 30.6 30.062 0 500 0 1.664

4 12000 24 medium 70 38.6 37.922 0 500 0 1.676

4 12000 24 high 90 38.6 37.922 0 500 0 2.140

4

3 3000 8 low 60 22.6 22.203 0 500 0 1.419

0.523 0.784

3 6000 16 low 60 30.6 30.062 0 500 0 1.430

4 8000 16 medium 70 30.6 30.062 0 500 0 1.664

4 12000 24 medium 70 38.6 37.922 0 500 0 1.676

4 12000 24 high 90 38.6 37.922 0 500 0 2.140

120

6

6 18000 24 medium/high 80

744 730.928 440000 500 310000 3.357

0.131 0.196 6 18000 24 high 90 744 730.928 440000 500 310000 3.589

6 30000 40 medium/high 90 760 746.647 440000 500 310000 3.617

6 30000 40 very high 90 760 746.647 440000 500 310000 3.617

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 3.357

0.065 0.098 6 18000 24 high 90 744 730.928 440000 500 310000 3.589

6 30000 40 medium/high 90 760 746.647 440000 500 310000 3.617

6 30000 40 very high 90 760 746.647 440000 500 310000 3.617

Blade Adjustment

2 3 1500 4 consumables 30

0.262

12.6 12.379 0 500 0 0.093 12.711 19.067

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.183

1.956 2.933

3 6000 16 low 60 30.6 30.062 0 500 0 0.194

4 8000 16 medium 70 30.6 30.062 0 500 0 0.222

4 12000 24 medium 70 38.6 37.922 0 500 0 0.234

4 12000 24 high 90 38.6 37.922 0 500 0 0.286

5 3 3000 8 low 50 10.6 10.414 0 500 0 0.145

3.911 5.867 4 8000 16 medium 60 18.6 18.273 0 500 0 0.184

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 1.709

0.978 1.467 6 18000 24 high 90 744 730.928 440000 500 310000 1.735

6 30000 40 medium/high 80 760 746.647 440000 500 310000 1.737

6 30000 40 very high 100 760 746.647 440000 500 310000 1.789

121

Hydraulic System

2 3 1500 4 consumables 30

12.6 12.379 0 500 0 0.093 0.643 0.965

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.183

0.429 0.643

3 6000 16 low 60 30.6 30.062 0 500 0 0.194

4 8000 16 medium 70 30.6 30.062 0 500 0 0.222

4 12000 24 medium 70 38.6 37.922 0 500 0 0.234

4 12000 24 high 90 38.6 37.922 0 500 0 0.286

Drive Train

2 3 1500 4 consumables 30

1.856

12.6 12.379 0 500 0 0.571 2.599 3.899

4

3 3000 8 low 60 22.6 22.203 0 500 0 1.139

2.599 3.899

3 6000 16 low 60 30.6 30.062 0 500 0 1.150

4 8000 16 medium 70 30.6 30.062 0 500 0 1.338

4 12000 24 medium 70 38.6 37.922 0 500 0 1.349

4 12000 24 high 90 38.6 37.922 0 500 0 1.721

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 2.984

0.578 0.866 6 18000 24 high 90 744 730.928 440000 500 310000 3.170

6 30000 40 medium/high 80 760 746.647 440000 500 310000 3.012

6 30000 40 very high 100 760 746.647 440000 500 310000 3.383

Yaw System

2 3 1500 4 consumables 30

0.123

12.6 12.379 0 500 0 0.051 4.568 6.853

5 3 3000 8 low 50 10.6 10.414 0 500 0 0.075

4.568 6.853 4 8000 16 medium 60 18.6 18.273 0 500 0 0.101

122

6

6 18000 24 medium/high 80

744 730.928 440000 500 310000 1.598

1.015 1.523 6 18000 24 high 90 744 730.928 440000 500 310000 1.610

6 30000 40 medium/high 80 760 746.647 440000 500 310000 1.626

6 30000 40 very high 100 760 746.647 440000 500 310000 1.650

Generator

2 3 1500 4 consumables 30

0.339

12.6 12.379 0 500 0 0.116 2.921 4.382

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.229

2.921 4.382

3 6000 16 low 60 30.6 30.062 0 500 0 0.240

4 8000 16 medium 70 30.6 30.062 0 500 0 0.276

4 12000 24 medium 70 38.6 37.922 0 500 0 0.288

4 12000 24 high 90 38.6 37.922 0 500 0 0.355

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 1.771

0.649 0.974 6 18000 24 high 90 744 730.928 440000 500 310000 1.804

6 30000 40 medium/high 80 760 746.647 440000 500 310000 1.798

6 30000 40 very high 100 760 746.647 440000 500 310000 1.866

Control and protection

system (generator)

2 3 1500 4 consumables 30 12.6 12.379 0 500 0 0.116 5.401 8.101

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.229

5.401 8.101

3 6000 16 low 60 30.6 30.062 0 500 0 0.240

4 8000 16 medium 70 30.6 30.062 0 500 0 0.276

4 12000 24 medium 70 38.6 37.922 0 500 0 0.288

4 12000 24 high 90 38.6 37.922 0 500 0 0.355

123

4

3 3000 8 low 60

22.6 22.203 0 500 0 0.229

1.200 1.800

3 6000 16 low 60 30.6 30.062 0 500 0 0.240

4 8000 16 medium 70 30.6 30.062 0 500 0 0.276

4 12000 24 medium 70 38.6 37.922 0 500 0 0.288

4 12000 24 high 90 38.6 37.922 0 500 0 0.355

Generator Lead/

transmission cables

2 3 1500 4 consumables 30 12.6 12.379 0 500 0 0.116 5.116 7.674

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.229

4.186 6.279

3 6000 16 low 60 30.6 30.062 0 500 0 0.240

4 8000 16 medium 70 30.6 30.062 0 500 0 0.276

4 12000 24 medium 70 38.6 37.922 0 500 0 0.288

4 12000 24 high 90 38.6 37.922 0 500 0 0.355

Transformer

2 3 1500 4 consumables 30

0.354

12.6 12.379 0 500 0 0.120 0.716 1.073

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.238

0.716 1.073

3 6000 16 low 60 30.6 30.062 0 500 0 0.249

4 8000 16 medium 70 30.6 30.062 0 500 0 0.286

4 12000 24 medium 70 38.6 37.922 0 500 0 0.298

4 12000 24 high 90 38.6 37.922 0 500 0 0.369

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.238

0.159 0.239

3 6000 16 low 60 30.6 30.062 0 500 0 0.249

4 8000 16 medium 70 30.6 30.062 0 500 0 0.286

4 12000 24 medium 70 38.6 37.922 0 500 0 0.298

4 12000 24 high 90 38.6 37.922 0 500 0 0.369

124

Machinery Enclosure

2 3 1500 4 consumables 30

0.133

12.6 12.379 0 500 0 0.054 0.110 0.166

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.105

0.166 0.248

3 6000 16 low 60 30.6 30.062 0 500 0 0.116

4 8000 16 medium 70 30.6 30.062 0 500 0 0.132

4 12000 24 medium 70 38.6 37.922 0 500 0 0.144

4 12000 24 high 90 38.6 37.922 0 500 0 0.170

Tower

2 3 1500 4 consumables 30

2.591

12.6 12.379 0 500 0 0.792 1.663 2.495

4

3 3000 8 low 60 22.6 22.203 0 500 0 1.580

0.907 1.361

3 6000 16 low 60 30.6 30.062 0 500 0 1.591

4 8000 16 medium 70 30.6 30.062 0 500 0 1.852

4 12000 24 medium 70 38.6 37.922 0 500 0 1.864

4 12000 24 high 90 38.6 37.922 0 500 0 2.382

4

3 3000 8 low 60 22.6 22.203 0 500 0 1.580

0.302 0.454

3 6000 16 low 60 30.6 30.062 0 500 0 1.591

4 8000 16 medium 70 30.6 30.062 0 500 0 1.852

4 12000 24 medium 70 38.6 37.922 0 500 0 1.864

4 12000 24 high 90 38.6 37.922 0 500 0 2.382

6

6 18000 24 medium/high 80 744 730.928 440000 500 310000 3.572

0.151 0.227 6 18000 24 high 90 744 730.928 440000 500 310000 3.831

6 30000 40 medium/high 80 760 746.647 440000 500 310000 3.600

6 30000 40 very high 100 760 746.647 440000 500 310000 4.118

125

Turbine control & protection

system

2 3 1500 4 consumables 30

0.010

12.6 12.379 0 500 0 0.017 9.478 14.216

4

3 3000 8 low 60 22.6 22.203 0 500 0 0.032

7.754 11.632

3 6000 16 low 60 30.6 30.062 0 500 0 0.042

4 8000 16 medium 70 30.6 30.062 0 500 0 0.045

4 12000 24 medium 70 38.6 37.922 0 500 0 0.057

4 12000 24 high 90 38.6 37.922 0 500 0 0.059

Windfarm Cables

4

3 3000 8 low 60

0.095

22.6 22.203 0 500 0 0.082

1.000 1.500

3 6000 16 low 60 30.6 30.062 0 500 0 0.093

4 8000 16 medium 70 30.6 30.062 0 500 0 0.105

4 12000 24 medium 70 38.6 37.922 0 500 0 0.117

4 12000 24 high 90 38.6 37.922 0 500 0 0.136

Table A-2 Cost Analysis Table of results

127

A.3 Maintenance Category Seven: Large Parts Preventive

Replacement

This is the new maintenance category created in order to optimise the maintenance

plan. It is based on the assumption that some large parts might need a preventive

replacement due to the detection of high level of degradation on them. This is

commonly known as Condition-based Maintenance, which presents some

advantages as downtime reduction, due to the fact that the WT has just to be shut

down during the replacement and it is not influenced by the logistic, organizational,

weather, and travel downtimes that the failure of the same part would imply. The

maintenance procedure for this category is the same than the one carried out in

category number six, therefore there is no necessity of explaining it again. The table

below shows all maintenance categories so a comparison between both, preventive

and non preventive replacements of large parts characteristics and downtime could

be done.

129

Maintenance categories

Nr

Description Total

downtime (hr)

Crew (Nr) Repair time (hr)

Repair Costs % of

subsystem's cost

Repair Strategy Logistic time (hr) Transit time (hr)

Access

equipment 2nd

Device 3rd

Device Equipment

logistic Spare parts

Organisation

Remote Reset 1 none 0 2 none 0

0 0 0 0

2

Inspection and small Repair Inside

2 small 3 4 consumables 30 1

0 0 6 2.6

12.6

Inspection and small Repair Outside

3 small 3 8 consumables 40 1 5 6 0 0 6 2.6

16.6

Replacement small parts (<2MT)

4

small 3 8 low 60 1 5

0 0 12 2.6

22.6

small 3 16 low 60 1 5

0 0 12 2.6

30.6

large 4 16 medium 70 1 5

0 0 12 2.6

30.6

large 4 24 medium 70 1 5

0 0 12 2.6

38.6

large 4 24 high 90 1 5

0 0 12 2.6

38.6

Preventive replacement Small

parts (< 2 MT) 5

small 3 8 low 50 1 5

0 0 12 2.6

10.6

large 4 16 medium 60 1 5

0 0 12 2.6

18.6

Replacement large parts (< 100 MT)

6

large 6 24 medium/

high 80 1 2

720 168 24 2.6

744

large 6 24 high 90 1 2

720 336 24 2.6

744

large 6 40 medium/

high 80 1 2

720 336 24 2.6

760

large 6 40 very high 100 1 2

720 336 24 2.6

760

Preventive replacement large parts (< 100MT)

7 large 6 24 high 80 1 2

720 336 24 2.6

26.6

large 6 24 very high 90 1 2

720 336 24 2.6

26.6

Table A-3 Maintenance Categories including Large Parts Preventive Replacement