Mooring Systems for

Floating Offshore Wind:

Integrity Management
Concepts, Risks and
Mitigation
World Forum Offshore Wind (WFO)
WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Imprint
Publisher: World Forum Offshore Wind e.V.

Author: David Timmington (Griffin-Woodhouse Limited)

Chairman Moorings Subcommittee

Louise Efthimiou (World Forum Offshore Wind e.V.)

Floating Offshore Wind Analyst

Contact: louise.efthimiou@wfo-global.org

Cover: Photo courtesy of BW Ideol and Centrale Nantes (V. Joncheray), Floatgen
demonstrator

Status: May 2022

© 2022 World Forum Offshore Wind e.V.

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Acknowledgments
WFO’s 80+ members represent the entire offshore wind value chain including but not limited
to utility companies, manufacturers, service firms, consultancies and other non-profit
organizations.

This document is the result of one year’s worth of monthly discussions between participating
WFO members during meetings of WFO’s Floating Offshore Wind Committee on the topic of
‘Mooring Systems for Floating Offshore Wind’. WFO would like to thank everyone who has
contributed their time and expertise during the discussions and additional analyses carried
out for this study.

Disclaimer
The views in this report do not necessarily represent the views of all WFO members but are
based on a synthesis of recorded insights undertaken by WFO and the WFO Moorings
Subcommittee Chairman over the last year. The findings are also designed to serve as an initial
account of the status, challenges and opportunities of floating offshore wind mooring systems
and therefore should not be generalised and are subject to evolve along with the industry.

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Foreword

One cannot diligently look at floating offshore wind without quickly drifting (no pun
intended) into the meanders of mooring systems and solutions. Their impact on CAPEX and
OPEX – without even tackling the environmental and recycling aspects – as well as the risks
that need to be carefully mitigated to avoid jeopordizing the revenue source of floating wind
(i.e. its dynamic electrical cable) are substantially more than anecdotal.

Pictures of capsized or drifting oil and gas structures still send shivers down the spines of
many lenders and insurance experts and definitely justify that serial-installed floating wind
assets (versus one-off oil & gas assets) deserve the most carefully engineered, sourced and
installed solutions. Our Insurance Subcommittee’s landmark initial white paper underlines the
need for such a responsible approach.

Having said that, cost-competitiveness remains essential in our nascent industry’s quest
to match and even improve on the Levelised Cost of Energy (LCoE) of bottom-fixed wind by
2030 at the latest. Past and current efforts of our members need to be applauded but also
require further support. Innovative materials and components as well as plug-and-play
solutions reducing pre-lay and hook-up times will drive cost down. Building up a supply chain
and creating local value as close as possible to each of our strategic markets while keeping a
careful eye on mooring solutions’ carbon footprint and their materials’ recycling options will
increasingly become key parameters in the purchasing decision process.

I thank our Subcommittee’s Chair and active members for their work; I trust that their
next white paper will bring even more relevant information to the market.

Floating wind is now, floating wind is big, floating wind is without a doubt going to be a
key – if not the major – contributor to many countries’ renewable energy targets.

Bruno G. GESCHIER
Chairman of WFO’s Floating Offshore Wind Committee
Chief Sales & Marketing Officer of BW Ideol
Chairman of FOWT’s Scientific and Technical Committee
Founding Chairman of WindEurope’s Floating Offshore Wind Task Force (now Work Group)

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Table of Contents

Foreword 4

1 Introduction 2

2 Mooring Systems for Floating Offshore Wind 3

2.1 Floating Foundations 3

2.2 Station-Keeping 4
2.3 Standards, Recommended Practice & Guidance 7
2.4 Levelised Cost of Energy 8
2.5 Insurability 9
2.6 Design Basis 10
2.7 Mooring Integrity Management 11

3 Risks & Mitigation 14

3.1 Failure Modes and Degradation Mechanisms 14

3.2 Failure Distribution 18
3.3 Innovations 20
3.3.1 Synthetic Rope 21
3.3.2 Load Reduction Devices 23
3.3.3 Digital Twins 24
3.4 Product Extensions 24
3.4.1 Shared Anchors 24
3.4.2 Tensioners 25
3.4.3 Connectors 26
3.4.4 Analysis Software 27
3.4.5 Remote Survey 27
3.5 Reporting Systems 28

4 Conclusions 29

Appendix - Governing Standards for FOW 31

WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

1 Introduction

The Moorings Subcommittee was founded as part of the Floating Offshore Wind
Committee (FOWC) under the auspices of the World Forum Offshore Wind (WFO). Members
whom attended the Moorings Subcommittee represent all sectors in the Floating Offshore
Wind (FOW) industry, ranging from major international developers and contractors to
research & development institutions, equipment manufacturers, engineering consultants,
classification agencies and insurers.

Alongside the Moorings Subcommittee, two other subcommittees were founded: the
Insurance Subcommittee and the Operation and Maintenance (O&M) Subcommittee. In
addition to their individual achievements, both groups represent a great contribution to the
work of the Moorings Subcommittee. The Insurance Subcommittee is focusing on
developments with respect to insurance and project finance, whilst the O&M Subcommittee
is analyzing different floating offshore wind maintenance and repair concepts. The three
Subcommittees mutually foster the evolution of a “floating offshore wind dialogue” in that
the outcomes of the discussions and the developments of the floating offshore wind know-
how are shared across all groups. This work will shortly be bolstered by the newly formed
Cables and Floating Substations Subcommittee which will further inform and guide the
groups' activities.

FLOATING
OFFSHORE WIND
COMMITTEE
[meets quarterly]

CABLES AND FLOATING

INSURANCE MOORINGS O&M SUBSTATIONS
SUBCOMMITTEE SUBCOMMITTEE SUBCOMMITTEE SUBCOMMITTEE
[meets monthly] [meets monthly] [meets monthly] [meets monthly]

Figure 1. WFO Floating Offshore Wind Committee Organizational Chart

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

2 Mooring Systems for Floating Offshore Wind

The majority of global offshore wind resource lies in water depths exceeding 60 metres,
which are not suited to conventional bottom-fixed turbines. Floating foundations are
therefore necessary to maximise this potential. Whilst the floating offshore wind industry has
been in development for more than a decade, there are limited small-scale/demonstrator
projects in the water, representing around 126MW of total installed capacity to-date.
However, current expectations are that up to 20.9GW of floating wind capacity will be
installed by 20351 and 264GW by 20502. This exponential growth, which requires rapid
progression from pre-commerical to full-scale arrays, poses a significant challenge but is one
that needs to be met if the industry is to deliver an energy transition that achieves global net
zero ambitions.

2.1 Floating Foundations

Prevailing substructure design concepts, derived from offshore oil and gas experience, are
illustrated below. Each has its own merits and challenges, but whilst spars account for the bulk
of currently installed capacity, they are expected to be quickly surpassed by semi-
submersibles based on projects presently in development -

Figure 2. Spar, Barge, TLP, Semi-Sub (from left to right)3

Spar: The spar has a deep draft and is a ballast-stabilised structure. A well-established and
simple technology that is inherently stable but has relatively large motions, its simple mooring
system typically requires long, heavy mooring lines.

1 BloombergNEF forecasts 5.3GW by 2030 and 20.9GW by 2035, Wind – 10 Predictions for 2022
2 DNV, Energy Transition Outlook 2021
3 Human exposure to motion during maintenance on floating offshore wind turbines, Scheu et al 2018, Ocean Engineering,
Volume 165

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Barge: Barges exhibit a square footprint and have the shallowest draft of all floating
foundations. They are subject to high wave-induced motions but may incorporate a moonpool
to supress this effect. Consequently, they require a more complex and robust mooring system.

Tension-Leg Platform (TLP): A tension-stabilised structure with relatively shallow draft, the
TLP has a high degree of restraint and therefore experiences limited motions. It has a small
footprint; however, significant vertical loads require mooring tendons to achieve high
pretensions.

Semi-Submersible: The semi-sub is a relatively shallow draft, buoyancy-stabilised

structure in which motions are limited by employing heave plates. It is a flexible foundation
which can utilise a range of simple mooring systems but requires ballasting.

2.2 Station-Keeping

Mooring systems are critical to the station-keeping4 of any permanent floating structure,
and whilst the oil and gas sector has an extensive track record in this area, there is limited
transferability when considering floating offshore wind. Wind farms of +1GW scale will
comprise arrays well in excess of 50 floating turbines each having a minimum of three mooring
lines, compared to deep water oil and gas terminals having single, very large structures
employing multiple lines.

Figure 3. Typical Semi-Sub 3x1-Line and 3x2-Line Mooring Spreads (from left to right)

Operating conditions are also challenging. Shallow water5 environments are non-linear, in
which dynamic loads need to be considered, whereas the weight of equipment required for
deep water6 locations must be overcome. Mooring systems will need to be adapted to suit
the substructure selected for each project, its overall design basis and individual site
conditions. Furthermore, protection of dynamic power cables from damage by floater
motions will be critical. Earthquake, tsunami, hurricane and typhoon risk will figure in certain
geographies; therefore, a broad range of solutions are likely to be developed rather than one
approach being favoured over another.

Floating foundations can be either ‘compliant’ or ‘restrained’ with respect to global

motions, which are described as the ‘six degrees of freedom’ and detailed in Table 1: surge,

4 To maintain a floating structure in a fixed position relative to a fixed point or within a defined sector relative to the fixed
point. The station-keeping system includes the mooring lines or tendons, as applicable, as well as the anchor foundations
that transfer forces from the system to the seabed.
5 Typically 60 - 300m deep characterized by wavelengths greater than 10 times the water depth
6 Usually +1,000m deep characterized by wavelengths shorter than about twice the water depth

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

sway, heave, roll, pitch and yaw. Spars, barges and semi-subs are compliant structures,
whereas TLPs are constrained.

Table 1. Source: Det Norske Veritas7

Surge Displacement along
(x) longditudinal axis

Sway Displacement along

(y) lateral axis

Heave Displacement along

(z) vertical axis

Roll Rotation about

longditudinal axis

Pitch Rotation about

lateral axis

Yaw Rotation about

vertical axis

Typical station-keeping systems of compliant floaters are based on taut, semi-taut or

catenary8 mooring lines that transfer loads acting on the floater to anchors installed in the
seabed. Anchoring solutions are decided on a case-by-case basis depending on the ground
conditions at site and mooring system in use. The variety of mooring configurations are
illustrated below (courtesy of First Marine Solutions, Morek Engineering and ORE Catapult’s
Floating Offshore Wind Centre of Excellence) and simply described as follows -

Plain Catenary: Comprising chain only between the anchor point and floater, the simple
catenary mooring is commonly employed in conventional shallow water environments.
Compliance is achieved by a restoring force characterised by the weight of chain employed,
as opposed to its strength.

Figure 4. Plain Catenary Mooring Spread

7 DNV-ST-0119 : Fig. 1-2

8 Catenary simply describes the shape a free hanging chain forms and is similar to one side of a parabola

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Multi-Catenary: An arrangement commonly utilising a synthetic rope/chain combination

line. Initial compliance is achieved by the visco-elastic properties of a taut rope section and
latterly by the weight of ground chain. Restoring force properties can be tuned by altering the
arrangement of weighted and compliant sections, i.e. by the addition of clump weights, but a
balance should be achieved between weight and stiffness to limit dynamic behaviour.

Figure 5. Multi-Catenary Mooring Spread

Buoyant Semi-Taut: Similary employing a synthetic rope/chain line, but with significantly
reduced ground chain. Buoyancy modules are attached to the rope to prevent damage
through contact with the seabed. Compliance is achieved predominantly by visco-elastic
properties of the rope and the anchor points will experience significantly increased vertical
uplift loads.

Figure 6. Buoyant Semi-Taut Mooring Spread

Taut: A system comprising rope tendons connected under tension to the anchor point.
Lines experience high loads and the anchor must withstand vertical uplift. Short sections of
chain and connectors may be employed at the termination points to allow the adjustment of
length and overall tension.

Figure 7. Taut Mooring Spread

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Fundamentally, a mooring system should maintain the position and attitude of the floating
structure and ensure the dynamic power cable remains within its design envelope. However,
‘optimisation’ of compliant mooring systems may result in non-redundant systems in which a
mooring line failure may lead to loss of position, possible collision with adjacent structures
and/or damage to power cables. Redundancy considerations are therefore an important part
of mooring design and form part of the basis for selection of appropriate consequence class (
which are outlined later).

Redundancy is a commonly used term but one which is often misunderstood. DNV, in its
Standard for Floating Wind Turbine Structures (DNV-ST-0119), provides guidance that in some
cases “… it is not so obvious if a station-keeping system is redundant or not. For example,
failure of a slack mooring line in a 3x1-line system, causing a large drift-off, does not
necessarily imply a system without redundancy.” As outlined later, the n+1 concept is
advocated as the preferred method of mitigating risk of single line failure, although
redundancy can be achieve in a number of different ways.

2.3 Standards, Recommended Practice & Guidance

Regulatory frameworks differ from country to country and consequently there is no single
global governing Standard with respect to the design, manufacture, assembly, installation,
commissioning, operation, maintenance and decommissioning of Floating Offshore Wind
Turbines (FOWT). However, a number of International Classification Societies have developed
technical Standards which incorporate existing Rules, but these require development in
response to innovation and growing operational experience. Furthermore, future
harmonization is necessary to prevent ambiguity. Governing standards for each Classification
Society are summarized below. Detailed individual frameworks can be found in the Appendix.

Table 2. Source: ORE Catapult, Floating Offshore Wind Centre of Excellence9

9 Standards Mapping Report, Sept 2021 : Table 1-1

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

2.4 Levelised Cost of Energy

Compared to onshore and offshore bottom-fixed wind, the cost of electricity generated
by floating wind turbines is relatively expensive. It is imperative to quickly bring down the
Levelized Cost of Energy (LCoE) and many forecasts predict price parity will be achieved in the
early 2030s. The ambition is to move quickly from initial demonstrator projects, bypassing
pre-commercial limited scale developments, to full-scale +1GW arrays. This is clearly
evidenced by bid results from Scotwind Leasing Round 1 where 10 of the 17 sites were
awarded to floating wind technologies, representing 14.5GW of 25GW total offshore wind
capacity.

It is anticipated that innovation and the adoption of new technologies will address the
various challenges and help drive down cost, as will the industrialisation of production and
deployment. The below forecast illustrates this trend with respect to various growth scenarios
in the UK market, both with and without innovation. However, as we will come to see, a lack
of experience/track record and its associated risks may preclude projects from securing
adequate insurance cover. Furthermore, increased pressure to optimise mooring systems, the
risk of serialisation of defects and lack of readiness in the supply chain/local content
availability could exacerbate this issue.

Figure 8. UK Floating Offshore Wind Cost Reduction vs BEIS Forecast Wholesale Electricity
Price. Source: ORE Catapult, Floating Offshore Wind Centre of Excellence10

10 Floating Offshore Wind: Cost Reduction Pathways to Subsidy Free, 2021

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

2.5 Insurability

The white paper published by WFO’s Insurance Subcommittee concerning ‘Insurability of

Floating Offshore Wind’ clearly lays out the basis for projects to demonstrate risk mitigation,
especially with respect to cables and moorings.

Whilst there is long-term experience in bottom-fixed offshore wind, availability of cover

for the nascent floating offshore wind sector is limited. There are few insurers willing to
underwrite this risk and the market has restricted capacity due to: the proliferation of floater
concepts, a wide variety of available mooring and anchoring systems, innovation/new
technologies being considered, and a lack of operational track record. Since 2020,
international insurers have started to respond to negative financial results by -

1. Reducing the coverage of insurance wordings

2. Increasing deductibles
3. Increasing premiums

Significant claims in the bottom-fixed offshore wind sector have recently compounded the
above reaction with both deductibles and premium levels for floating offshore wind projects
being many times higher than for bottom-fixed. Furthermore, the application of London
Engineering Group11 (LEG) clauses may be limited to LEG 1 and LEG 2 until suitable experience
is established. Consequently, insurer(s) shall not be liable for -

LEG 1/96 - Loss or damage due to defects of material workmanship design plan or
specification, i.e. completely excludes the loss or damage and the loss of
revenue
LEG 2/96 - All costs rendered necessary by defects of material workmanship design plan
specification and should damage occur to any portion of the Insured Property
containing any of the said defects the cost of replacement or rectification
which is hereby excluded is that cost which would have been incurred if
replacement or rectification of the Insured Property had been put in hand
immediately prior to the said damage, i.e. excludes the costs which would
have been incurred immediately before the loss or damage occurred, but not
loss or revenue

It may be some time before coverage will extend to the higher LEG 3 wording, i.e. only
excluding the costs for improvements and betterments (not loss, damage or loss of revenue).

LEG 3/06 - All costs rendered necessary by defects of material workmanship design plan
or specification and should damage (which for the purposes of this exclusion
shall include any patent detrimental change in the physical condition of the
Insured Property) occur to any portion of the Insured Property containing any
of the said defects the cost of replacement or rectification which is hereby

London Engineering Group is a consultative body for insurers of engineering class. The group produces coverage clauses
11

which vary in their exclusions with respect to engineering risks

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

excluded is that cost incurred to improve the original material workmanship

design plan or specification.

At this stage, there is no clear relationship between classification and LEG-insurability,

which means projects using new technologies with limited track records should consider
quantifying the additional risk between LEG 1 and LEG 2 at a very early stage and establish
risk mitigation measures. Projects planning to use new technologies which offer promising
cost-saving perspectives might be willing and able to take the additional risk between LEG 2
and LEG 1 and to mitigate it technically. Such an early-stage risk analysis and mitigation
methodology will have an important impact on the availability of Project Finance.

2.6 Design Basis

The purpose of any mooring system is to maintain station and control floater ‘global
motions’ as described in Section 2.2. Systems will vary according to prevailing environmental
conditions, water depth, ground conditions, floater type, mooring arrangement and power
cable dynamic configuration selected. The applicable ‘Standards, Recommended Practices
and Guidance’ are identified in Section 2.3, and each design should comply with prescribed
‘limit states’ defined therein -

1. Ultimate Limit State (ULS) - maximum structural stiffness or load-carrying capacity of

the intact system beyond which the probability of failure is unacceptable
2. Fatigue Limit State (FLS) - maximum stress concentration or damage accumulation,
resulting in structural failure due to cyclic loading below the ULS
3. Accidental Limit State (ALS) - the minimum survival condition required to maintain
structural integrity in a damaged condition (transient and stationary), or in presence
of abnormal environmental conditions. The return period for which defines the
number of years between events characterized by a similar magnitude, e.g. a 50-year
wave height, has a 2% probability of being exceeded in any one year

Target safety levels, which vary from country to country, are defined and each design is
attributed a class according to the consequences of a structural failure -

1. Consequence Class 1 (CC1) - where failure is unlikely to lead to unacceptable

consequences such as loss of life, collision with an adjacent structure, and
environmental impacts
2. Consequence Class 2 (CC2) - where failure may well lead to unacceptable
consequences of these types

Target safety levels for mooring systems relate to an annual probability of failure of 1 x
10 for CC1 or 1 x 10!# for CC2.
!"

Typically, mooring systems are designed to achieve CC1 unless they are non-redundant, in
which case CC2 applies. DNV-ST-0119 defines redundancy as the “…ability of a component or
system to maintain or restore its function after a failure of a member or connection has

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

occurred.” For example, if one mooring line is lost, the remaining part of the mooring system
must meet the ALS criterion for at least a one-year12 load for post-damage cases, provided
that the damage is controlled within a reasonably short timeframe, as well as a robustness
check for the intact system in 500-year return period conditions. Consequently, redundancy
can be achieved in different ways and its practical application is the balance between ULS and
ALS –

1. Alternative Load Paths - The n+113 concept is advocated as the preferred method of
mitigating risk of single line failure, i.e. having 3x2-line as opposed to 3x1-line mooring
spreads, where the remaining lines maintain station-keeping closer to the floater’s
original position
2. Strengthening - Improving the structural integrity of remaining mooring lines to
accommodate the ALS load case when the turbine may be considerably offset from its
regular operating position, i.e. increasing the size of equipment employed

In addition to this, each design should consider ‘robustness’ against possible systematic
errors. For instance, the less mature a technology, the higher the need for robustness. Whilst
it is expected that innovation and the adoption of new technologies will overcome various
challenges and drive down LCoE, the limited availability of project finance/insurance cover as
well as the potential for serialisation of defects may warrant a conservative approach at first.

DNV-RP-E308 suggests “…mooring design starts with a whole-system quantitative risk

assessment. The risk analysis should study different line failure scenarios and consider the
potential drift-off consequences. Understanding the risk profile and the risk reduction
required to bring scenarios and consequences to an acceptable level provides a way to
compare strategies to achieve commensurate expenditure on the mooring system.”

DNV-RP-0286 recommends “…global analysis of floating offshore wind turbines, including

substructures, and of separate components, i.e. wind turbine, floater and station-keeping
systems.” This so-called ‘Coupled Analysis’ makes sure the real-time interactions between
these elements are taken into account synchronously during the design stage. The coupled
analysis should be performed in time domain with aero-hydro-servo-elastic simulation codes
in order to capture the typically non-linear system behaviour of mooring systems of FOWTs.

2.7 Mooring Integrity Management

A seminal study14 into mooring failures in oil and gas floating production systems between
1997 and 2013 reported single line failure rates of 2.5 x 10!$ per line per year and multiple
line failure rates ≈3.5 x 10!$ per unit per year, i.e. much higher than prescribed in the relevant

12 The load resulting from extreme environmental conditions expected to occur within a year
13The n-1 notation was previously referenced in the Insurance Subcommittee White Paper, but both are valid. For instance,
in Germany, “n-1 Sicherheit” means in the event of a failure, the mooring system maintains FOWT position and energy
production
14OTC-25273-MS: Industry Survey of Past Failures, Pre-emptive Replacements and Reported Degradations for Mooring
Systems of Floating Production Units, Fontaine et al 2014

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design codes. The resulting improvements in understanding and managing failure

modes/degradation mechanisms has no doubt reduced these rates. However, direct
translation of these results to develop corresponding failure rates for FOWT moorings is
problematic at present, despite many of the underlying degradation threats across the life
cycle of an oil and gas floating production mooring system being applicable. A recent
assessment by DNV estimated mooring system failure rates for floating wind of between 0.1%
- 2%15, leading them to express an opinion that developers should “…plan for failure.”
Therefore, mooring integrity issues need to be given much greater consideration during the
design phase and applied throughout the mooring life cycle.

Figure 9. Mooring System Life Cycle16 Figure 10. Integrity Management Process16

Mooring Integrity Management (MIM) is a process for ensuring a mooring’s fitness-for-

service over its entire life cycle (see Fig. 9 and 10), managing the effects of damage,
deterioration, changes in loading and accidental overload. MIM programmes should detect
abnormal conditions or factors outwith the original design envelope through regular
inspection and monitoring. The process is iterative, providing data that may be used to
undertake remedial action, protect against accidents or loss, estimate remaining service life
and support life extension requests. By monitoring the response of various aspects of the
system, changes can be identified and rectification actioned.

The integrity management (IM) process provides an opportunity to adopt risk-based

principles that consider the likelihood of damage and its potential consequences in order to
develop a risk matrix (see Fig. 11). Mitigation should be put in place to reduce or remove
identified risks and/or consequence of failure, and a list of initiation triggers should be
developed to determine if parameters have changed. Typical examples include changes in
platform offset, differences in magnitude or frequency responses from load monitoring.
Immediate and short-term incident response planning should also be evaluated along with
the availability and condition of any spares or emergency repair equipment. Note, however,
the risk profile of a mooring may change over time.

A fitness-for-service assessment should be performed if an initiation trigger was identified

in the evaluation of IM data. Likewise, a recent failure in a similar mooring system, research

15 DNV Presentation: Moorings Subcommittee #2, K. Argyriadis and A. Argyros 2021

16 DNV-RP-E308 - Mooring Integrity Management

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that invalidates original design assumptions, changes in environmental or operating

conditions should also prompt a review. Therefore, the IM process should be defined as early
as possible in the design phase and an inspection plan drawn-up identifying the frequency and
scope of inspections, methods and equipment to be used.

(1) Risk Level 1 - RED - major focus of

resources, increased inspection
frequency/intensity and/or more
detailed engineering
(2) Risk Level 2 - YELLOW -moderate
focus of resources
(3) Risk Level 3 - GREEN - less focus of
resources, reduced inspection
frequency and/or scope

Figure 11. Risk Categorisation Matrix17

Integrity management data falls into two broad categories -

1. Characteristic Data - the baseline data that represents the mooring at installation and
includes the as-designed condition, as-built condition, and as-installed condition
2. Condition Data - represents the changes to characteristic data that have occurred
during the life of the mooring and include data from in-service inspections, damage
evaluation, corrosion protection; strengthening, modification or repair data; condition
monitoring data and operational incident data

Inspection and monitoring are therefore key elements of any IM programme and a Risk
Based Inspection (RBI) approach is usually adopted. Direct measurement through continual
monitoring, periodic measurement or visual inspections are preferred; however, inferences
from indirect measurements, i.e. platform motions and ‘Digital Twins’, may be used. A risk
assessment should then be employed to rank the criticality of certain mooring components
within the matrix, but other factors such as interfaces between equipment, location within
the line, fatigue, corrosion and other degradation mechanisms should be considered. Of
course, the condition of monitoring systems themselves should not be overlooked by any IM
strategy.

17 API RP 2MIM – Mooring Integrity Management

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3 Risks & Mitigation

There are no reported failures in FOWT mooring lines to-date, but this is perhaps due to
there being few small-scale/demonstrator projects in the water for a limited time.
Furthermore, these are not located in the harshest operating environments and likely employ
cautiously over-engineered mooring systems (as is common for emerging technologies).
However, if as detailed in Section 2.7 that annual single line failure rates are estimated in the
region 0.1% - 2%, an understanding of the main threats and associated mitigations is critical.
Whilst innovation and new technologies are expected to overcome many challenges, risk will
be higher in the short-term due to limited track record and experience, which may be
compounded by rapid progression to full scale +1GW arrays utilising a serialised approach.
Therefore, the consequence of early failures may be a lack of insurance cover or project
finance that might curtail the industry’s growth. An early conservative approach is therefore
warranted.

Importantly, we also need to understand what constitutes a ‘failure’, which does not
necessarily imply a catastrophic event where damage causes the loss of one or more lines. For
example, it may be a reduction of tension in which floater excursion falls outside the design
envelope, risking damage to power cables; or indeed the pre-emptive replacement of
equipment identified by an integrity management programme as being damaged or degraded
beyond design expectations. In each case, energy production may be interrupted, causing loss
of revenue if not a total FAILURE
loss ofEVENT
the floater.
TYPE

Single Line Failure,

Pre-emptive 42%
Replacement, 39%

Reported Degradation, Multiple Line Failure,

11% 8%

Figure 12. Failure Event Type

Source: OTC-25273-MS

3.1 Failure Modes and Degradation Mechanisms

Common failure modes and degradation mechanisms are well understood as evidenced
by findings from the aforementioned OTC-25273-MS study into mooring failures in oil and gas
floating production systems (refer Fig. 13 to Fig. 16 below). The most prevalent causes of
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single line failures were fatigue18 and corrosion19, with 49% of damage sustained during
operation, 19% of failures due to design issues and 6% attributed to manufacturing
(construction).

Design issues will vary with floater type/mooring system selected and be affected by
type/configuration of equipment within the mooring line. However, issues may be addressed
by ensuring sufficient and accurate site data is available, that adequate strength/fatigue
analysis has been performed, likely failure modes are assessed and coupled analysis
conducted. Furthermore, the design should set out a clear integrity management
strategy/philosophy and provide for easy change-out/replacement of equipment where
necessary.

Manufacturing issues should be controlled through careful selection of approved suppliers

with proven experience and equipment/technology track-record. A robust ‘Quality
Assurance/Quality Control’ system that fully documents the results of tests in accordance with
class rules and highlights non-conformances/remedial actions taken is essential to
establishing the ‘as-built’ condition necessary for distinguishing between manufacturing
defects and infant mortality due to random or unknown failure mechanisms. Results should
be independently verified and enhanced testing regimes considered, including Non-
Destructive Examination (NDE), e.g. radiographic, ultrasonic,
PHASE magnetic particle inspection.
OF FAILURE EVENT
PREVALENT FAILURE MODES

Overload, 1% Multiple Causes, 3% Unknown, 4%

Construction, 6%

Corrosion,
11%
Design,
Mechanical, 19%
Fatigue/
16%
Corrosion,
Manufacturing 11%
Defect, 5% Installation,
Out of Plane Bending 22%
Fatigue, 4%

Installation,
18% Fatigue,
24% Operation,
49%
Design,
7%

Figure 13. Prevalent Failure Modes Figure 14. Phase of Failure Event
Source: OTC-25273-MS

The most commonly failed component is chain representing 46% of all events, of which
almost half occurred in the upper sections, particularly at the stopper/fairlead. Behaviour of
chain links in this section should therefore be carefully evaluated during the design phase to
minimize the risk of failure, and particular attention should be paid to corrosion in the splash
zone. However, chain is the most represented component, being present in 76% of surveyed
systems and subject to the highest pre-emptive replacement.

18 Initiation and propagation of cracks due to cyclic loading

19The deterioration of a material through chemical reaction. Typically chemical or electrochemical whereby metal degrades
through oxidisation, but may also be induced by microbiological activity

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Failures associated with steel wire rope account for 31% of all events, which is unsurprising
as it is more easily damaged during installation but was also widely represented in 47% of
systems. However, multiple line failure events are dominated by wire at 60% compared to
13% for chain, suggesting chain degradation can be adequately controlled through an
appropriate IM programme. It is also worth noting that reported failures in polyester ropes,
which represent only 3% of the total survey, were all caused by mechanical damage. However,
these statistics may be somewhat distorted as the use of polyester for permanent moorings
was in its infancy at the time of the survey with only 9% of facilities using or having used it.
SINGLE LINE FAILURE BY COMPONENT PRE-EMPTIVE REPLACEMENT BY COMPONENT
Consequently, prevalent failure modes may have not yet emerged.

Other
Component, Connectors, 0%
Polyester Rope, 0% Other
11%
Component,
16%

Connectors, Chain,
20% 54%

Steel Wire Chain,

Rope, 26% 58%

Polyester Rope, 3% Steel Wire

Rope, 12%

Figure 15. Single Line Failure Figure 16. Pre-emptive Replacement

by Component by Component
Source: OTC-25273-MS

A small number of ‘Out-of Plane Bending’ (OPB) failures were reported, but these are
becoming increasingly relevant. OPB is a somewhat new phenomenon identified in 2002
following the failure, at the fairlead, of 3 mooring lines on TotalFinaElf’s offloading buoy at
the Girassol deep water field, offhsore Angola. Loss of inter-link articulation under load causes
one link to behave like a beam whilst the adjacent link is subject to rotational displacement
from first order floater motions. This induces cyclic bending stresses which accumulate to
cause crack initiation and rapid popagation to fatigue failure. The below images (courtesy of
AMOG) highlight bending stresses associated with tension-tension in-plane and out-of-plane
bending. DNV20 noted that a better understanding of OPB, especially in systems with high
pretensions, can help remove unnecessary conservatism associated with costly and heavy
multi-level articulated chain stoppers. Dedicated OPB testing of chain samples at the 1:1
project scale is necessary to enable design optimisation.

dnv.com Laboratories and Test Facilities Article: Cross-learning between oil and gas and floating offshore wind:
20

Optimizing mooring design to cut cost and weight, Pedro Barros 2021

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Figure 17. In-Plane Bending Figure 18. Out-of-Plane Bending

Source: AMOG Consulting21

One less well understood but important factor is ‘installation’ which represents 18% of
failures, with 22% of damage caused during the installation phase. Risks may vary according
to design choices made, e.g. anchor type, line configuration, upper connection mechanism
and tensioning system. The type and critically the size of equipment will also have a bearing
on the installation campaign, vessel selection and ultimately cost. To mitigate these threats,
a detailed risk assessment should be undertaken during the design stage which takes account
of onshore mobilisation activities and possible seabed congestion, including potential damage
to power cables during pre-lay, wet-storage and hook-up activities. The main concerns are
damage caused during handling which may result from twisting, side-loading/overloading,
misassembled items or poorly designed connections and unauthorized repairs (e.g. welding).
Poor anchor installation/positioning and incorrect or inconsistent line pretensions may also
result in failure.

The white paper published by WFO’s O&M Subcommittee regarding ‘Challenges and
Opportunities of Major Maintenance for Floating Offshore Wind’ clearly identified the need
to de-risk operations by designing specific procedures. Therefore, detailed installation plans
and handling procedures should be developed that consider necessary tooling, crew training
and monitoring processes. Integrity management activities should not be neglected at this
stage with the verified ‘as-installed’ condition also being critical to distinguishing between
installation damage, manufacturing defects and infant mortality due to random or unknown
failure mechanisms.

Many of the underlying degradation threats of oil and gas floating production systems
outlined above will be applicable to FOWT moorings, and the criticality of certain locations
within the mooring line will remain important, e.g. top chains, connectors and interfaces
between equipment. However, floating wind turbines present a very different mooring
challenge compared to oil and gas. The design basis and line configuration may differ
dramatically, not least in non-linear shallow water environments where dynamic loads need
to be considered. In addition, the thrust force from the turbine is large and inceases
quadratically with the wind speed up to the rated wind speed22. For higher wind speeds above
rated, the mean thrust decreases again through the controller, which protects the turbine
from overloading (see Fig. 19). As a consequence, FOWT mooring lines are likely to run at

21 OMAE2020-18609: Investigations Into Fatigue of OPB Loaded Offshore Mooring Chains, Farrow et al 2020
22Rated wind speed is the wind speed up to which the wind turbine extracts the maximum possible power from the wind.
At higher wind speeds, a non-zero blade pitch angle leads to a constant mean power equal to the rated power of the
turbine, through suboptimal operation and therefore reduced loads. The rated wind speed is for most turbines around
30% above common mean wind speeds.

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

higher mean loads for the life of the field as large forces appear for a significant percentage
of the turbine’s lifetime.

Regarding fluctuating thrust loads, another important aspect is the "negative damping"
induced by the blade pitch controller, the controller active above rated wind speeds. The
negative damping means that the FOWT damping, especially in the platform pitch degree of
freedom, becomes very small or even negative. There are various controller design
methodologies to avoid this negative damping phenomenon. Still, a risk remains for the
controller to not behave as expected, i.e. following a change in system parameters away from
the design condition. Such a change could therefore lead to increased fatigue loads on
different components and should be taken into account in the risk assessment.

Subsequently, a number of failure modes and degradation mechanisms will not yet be
understood. Furthermore, it is anticipated that the use of chain and wire will be significantly
reduced in favour of synthetic rope and new technologies employed. Novel failure
mechanisms will be particularly challenging because, by nature, they are unforeseen and
cannot be easily prevented by existing integrity practices.

Figure 19. Generator Power and Rotor Thrust Curves as a Function of Wind Speed
Source: IEA Wind TCP Task 3723

3.2 Failure Distribution

The bathtub curve, so-called because of its shape, is widely used to describe the reliability
of a product and/or pattern of failure generally observed. It is illustrated in Fig. 20 by the blue
line. The vertical axis represents the failure rate and horizontal axis time. The resultant curve
is achieved by mapping three distinct functions -

1. A decreasing failure rate characterized by early failures, illustrated by the red line
2. A constant and random failure rate, shown by the green line
3. An increasing failure rate characterized by late failures, exhibited as a yellow line

23 Definition of the IEA Wind 15-Megawatt offshore reference wind turbine, Gaertner et al 2020

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Figure 20. The ‘Bathtub Curve’

Source: U.S. Army document, retrieved from Wikipedia

‘Infant Mortality’ is an issue originally highlighted by a study into high failure rates of
permanent mooring systems in the offshore oil and gas industry during the period 2001-
201124. The study observed that “More than half of [failure] incidents happened during the
first 5 years of their design lives” with more occurring within “…the very first year than any
other year.” These early failures are associated with design faults, manufacturing defects and
installation damage, often becoming evident during the first significant loading event (e.g.
storms). Integrity management is crucial at this stage: an enhanced inspection regime is
recommended during the first 3 to 5 years of operation, which will help identify novel failure
mechanisms. Most importantly, the characteristic ‘as-designed’, ‘as-built’ and ‘as-installed’
condition records are critical to establishing baseline data for on-going structural health
monitoring.

The central section of the curve, or ‘Useful Life’, is the most stable with lowest combined
failure rate. Infant mortality threats have subsided and common failure modes/degradation
mechanisms are not yet prevalent. Failures are likely to be random and typically associated
with accidental overload, incidents and stochastic events, e.g. damage to synthetic rope
caused by over-trawling. Integrity management, however, remains important for condition
monitoring and fitness-for-service assessment.

The latter part of the curve, or 'Wear Out’ period, corresponds with accelerated
degradation, e.g. fatigue, corrosion and wear. Consequently the failure rate increases and
threats become a focus of concern. Integrity management is key in developing intervention
strategies/emergency responses to improve availability.

The impact of Regulatory ‘Shut-In’25 criteria in failed line conditions should also be
understood. Allowable operating states and acceptable insurance risks should be identified

24 OTC 24025: A Historical Review on Integrity Issues of Permanent Mooring Systems, Ma et al 2013
Term used in the oil and gas industry to describe the authority of a Regulator, i.e. Health & Safety Executive’s Energy
25

Division in UK, to shut down production of an asset in the event of a safety issue

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

and mitigations considered. In relation to sparing strategies, Ma et al20 observed the

“…availability of spare[s]… during installation allows for relatively easy replacement of
components that get damaged, as there are many instances of damaged components being
installed and ‘accepted’ as no spares were available. The spare components also provide the
ability to replace a damaged or failed leg more rapidly, as manufacturing a replacement can
take 6 to 12 months. Designing the original mooring system for ease of installation and
replacement can indirectly lead to better mooring integrity and should be included in the
original mooring system specification.” Similarly, the earlier referenced O&M white paper
identified the need for innovations in mooring connectors that allow for quick connection-
disconnection and a spare parts strategy to reduce downtime and loss of revenue. This is
particularly relevant to common, serialised mooring designs that may improve overall
availability.

3.3 Innovations

Innovations essential to the commercialization of floating offshore wind need to

achieve sufficient Technology Readiness Levels (TRL) to secure project financing and insurance
coverage. The American Petroleum Institute’s (API) 17N TRL methodology was initially drafted
in 2009 for the qualification of subsea equipment. The table has since been “written into major
petroleum companies’ procedures as a tool to assess the level of progress of subsea design,
fabrication and components’ qualification”26 and should therefore be considered suitable
floating offshore wind applications.

Figure 21. TRL for Subsea Technology Readiness Level Assessment

Source: API 2009

26 Subsea system readiness level assessment, Yasseri 2013, Underwater Technology, Volume 31, Number 2

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Recent Insurance Subcommittee meetings highlighted the challenge for new products to
achieve a minimum TRL 6 (i.e. successfully perform in a demonstrator project), and particularly
their transition to TRL 7 (i.e. successfully perform in a commercial-scale project). Further
discussions identified the following critical questions -

1. Given very limited opportunities for integration within demonstrator projects, how can
products quickly qualify the highest TRLs at commercial scale to meet rapid LCoE
reduction objectives?
2. It was considered that progress through TRLs 1-5 is relatively straightforward.
However, who will be responsibile for TRL assessment and accreditation, especially at
TRLs 6-7 and particularly when products perform as part of a system?
3. What is the threshold at which insurers are comfortable underwriting new
technologies or, as detailed in Section 2.5, must projects initially adopt the risk
between LEG 1 and LEG 2? Furthermore, to attain higher coverage, will insurers
mandate independent evaluation schemes, i.e. type approval and classification, that
assess readiness and consider manufacturing elements?

The transition from TRL 6 to 7 will require wider participation. Suppliers should be ready
to drive progress and provide transparency to their clients, i.e. project developers; industry
collaboration will be key to overcoming intellectual property issues and restrictive contractual
clauses to allow an innovation’s use across multiple projects; and a standardized approach, at
the commercial level, should be developed for the floating wind industry. In the meantime,
technical risk assessment and mitigation strategies as part of an overall mooring integrity
management programme will enable projects to properly handle the adoption of new
technologies. Dialogue with insurers and financers, and perhaps dedicated government
support in the form of technology development grants or adopting a position as insurer of
last resort, may help shape a common understanding of such technical risk mitigation
programmes and ultimately increase comfort levels.

3.3.1 Synthetic Rope

It is expected that the use of wire rope and chain will be reduced in favour of synthetic
rope; however, their deployment in offshore mooring systems is by no means new. In 1995,
Petrobras’ FPSO27 P13 was the first permanently moored platform to use synthetic rope,
which paved the way for development of polyester mooring systems that now have a well-
proven track record with more than 1,000 kilometres installed globally.

Synthetic ropes have no corrosion issues, superior fatigue performance and lower
observed failure rates. They are cost-effective, suitable for mass production and have good
handleability/transportability. A range of yarns are available, each displaying different
compliance characteristics, and their selection is based on a variety of factors to suit the
mooring design, e.g. construction, visco-elastic behaviour, creep, UV resistance and cost. They
have been adopted successfully by several FOWT developers in a number of demonstrator
projects and are undergoing further qualification for shallow water environments.

27 Offshore oil and gas Floating Production Storage and Offloading unit

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Typically, fibre ropes have been deployed in deep water environments where weight is
critical and stiffness important to minimizing offset. However, an emerging trend is towards
mooring systems with greater compliance which allows for shorter lines and lower breaking
loads. Designers are therefore exploring the elasticity of nylon ropes. Whilst nylon has been
used extensively in the oil and gas industry for temporary mooring applications, these ropes
have not been validated for use in long-term mooring applications in the same way as
polyester and HMPE as the material is unlikely to achieve a high fatigue life without the use
of special lubricants.

The use of synthetic rope will enable costs savings, not only from reduced mooring
footprints but also relative material cost and operational reliability. Still, achieving high line
pretensions may be challenging and there are specific design issues which need to be
addressed -

1. Marine fouling, a highly localised issue in which the growth of marine organisms
within the top 30m of water can result in rope penetration/damage, increased drag
and added weight to the mooring line, affecting its overall response. In most cases
these threats can be mitigated by the addition of protective filters/jackets and a
comprehensive ROV cleaning regime
2. Seabed contact resulting in materials ingress, accelerated wear and/or abrasion. This
threat may also be mitigated by the used of filters/custom designed jackets and the
use of buoyant ropes/buoyancy units to keep ropes from seabed contact. However,
potential damage at the connection point with buoyancy units should not be
discounted
3. Mechanical damage, mentioned in Section 3.1 as being responsible for 100% of
failures observed in polyester ropes, may also be protected against by cut-resitant
jackets. However, threats from impact events such as over-trawling might be mitigated
through the deployment of marine traffic monitoring, advanced warning systems and
ongoing dialogue with fisheries and port authorities
4. Some fibre ropes rely upon seawater as a cooling medium, so in these instances the
anchor points for fibre mooring lines should remain below sea level

Figure 22. Fibre Rope Stress/Strain Behaviour Comparison28 Figure 23. Marine Fouling29

28OTC-30830-MS: Evaluating Offshore Rope Fibres: Impact on Mooring Systems Integrity and Performance, Bastos et al
2020
29 Bridon-Bekaert Ropes Group Presentation: Moorings Subcommittee Meeting #8, C. Dewijngaert 2021

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The rapid scale-up of rope manufacturing is not expected to be a problem; however,

conventional rope terminations requiring splicing does present a major bottleneck with very
few skilled exponents globally. Therefore, new termination methodologies will need to be
developed to speed up delivery. Decommissioning of mooring lines comprising high volumes
of synthetic rope should be considered as the material is not currently recyclable.

3.3.2 Load Reduction Devices

Load Reduction Devices (LRDs) are a new concept of which there are a variety of designs
at differing stages of qualification. LRDs address the issue of high wind thrust loads and
dynamic wave action by providing compliance in a passive, non-linear fashion and can be
incorporated anywhere in the mooring line (but usually in the upper sections). The effect is a
more than 50% reduction in peak loading and 30% reduction in fatigue cycle amplitude,
resulting in an estimated 5-8% saving in CAPEX assuming an equivalent reduction in
equipment size and therefore installation costs. An associated reduction in OPEX is also
possible through reduced damage and increased platform/turbine uptime, which coupled
with potential life extension results in reduced LCoE.

Figure 24. Force vs. Extension Response Curve (courtesy of Dublin Offshore)

Figure 25. Peak Load Comparison (courtesy of Tfi Marine)

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Importantly, seabed impact can be lessened through reduced mooring footprints; LRDs
may help alleviate supply chain pressures by reducing demand for equipment; increased
storm protection may allow exploitation of more aggressive sites; and units may provide real-
time data used for operations, identifying extreme events, evaluating fatigue and supporting
digital twins.

3.3.3 Digital Twins

As set-out in Section 2.7, IM programmes usually adopt a risk-based approach, i.e. direct
measurement through continual monitoring, periodic measurement or visual inspections.
However, there are certain limitations, e.g. lack of accessibility due to equipment location,
marine growth and poor data/reliability (especially from subsea load cells). Therefore,
inferences regards global motions made from indirect measurements might also be used.
These so-called ‘digital twins’ typically utilise ‘motion and position’ data from DGPS30 and infer
‘mooring line tensions’ from triaxial Accelerometers & Gyroscopes to model and determine
fatigue damage.

The ultimate aim is to limit the use of subsea inspections, reduce operating costs, provide
continuous anomaly detection and remote warning systems that trigger incident/emergency
response, inform risk-based inspections and enhance sparing strategies. The technology is
relatively inexpensive and limited data transfer is required; however, developers should take
care to specify the most reliable and robust instrumentation available. Furthermore, whilst
artificial intelligence, neural networks and machine learning are being used more widely, the
algorithms need training to detect abnormal conditions and should be refined over time to
reduce the number of identified anomalies. The process should be iterative with models
continually adjusted to integrate baseline characteristic data, cumulative damage,
unexpected events and on-going condition data. Solving issues on data sharing and ownership
between multiple stakeholders will also be critical for developing fully-integrated digital twins
that support integrity management programmes, optimise mooring designs and individual
component improvements. This challenge was reflected in comments during the Moorings
Subcommittee discussions: “Trying to make interconnections between instruments and
hardware is very difficult. We have the data technology and analysis models but tying them
all together is the issue.”

3.4 Product Extensions

3.4.1 Shared Anchors

There are a variety of options with respect to anchors, e.g. drag embedment, vertically
loaded (VLA), pile (suction, diven, torpedo, micro, helical), suction embedment plate (SEPLA),
whose selection will be influenced by local soil conditions and have a bearing on mooring
system type/arrangement. Shared anchor systems, where multiple floater lines are connected
to one anchor, are currently being developed. For example, Equinor’s Hywind Tampen project

30Differential GPS provides improved accuracy from 15m nominal GPS accuracy down to 1-3cm at best, and ideally will
provide horizontal position and altitude

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

will use 19 anchors for 11 turbines, which is dramatically less than the earlier Hywind Scotland
project that used 15 anchors on 5 turbines. The benefits are an associated reduction in
equipment cost by a factor of up to 6 for certain geometries, fewer expensive geotechnical
site investigations and reduction in peak demand by up to 30%. However, anchors will need
to resist multiple-directional loading and the impact on soil capacity. Furthermore, these
arrangements may be more suited to deep water environments and the consequence of
cascade effects resulting from single/multiple line failures will need to be addressed. Lastly,
standardisation and advanced modelling need to be considered. The Moorings Subcommittee
reflected that shared anchors are “…technically possible, but added components, multiple
failure modes, n+1 configuraitons and complex installation may offset any saving in mooring
line cost.” Shared moorings are also being considered (refer Fig. 27) but are further away from
being well understood, let alone deployed.

Figure 26. Shared Anchor Geometries31 Figure 27. Shared Mooring Concept32

3.4.2 Tensioners
Tensioning systems to facilitate, quicken and improve the safety of installation and
adjustment of mooring line tension will be particularly important as the industry scales up.
Temporary chain shortening clutches used in oil and gas apply a vertical pulling force that is
40% of the equivalent load generated by horizontal reaction forces used to pull in drag
embedment anchors. Repeated heaving and slacking of the clutch builds up load in the
mooring chain until the required tension is achieved. The equipment can also be used for two-
way cross tensioning of opposing anchors, or three-way tensioning with the addition of a link
plate, thereby reducing the number of operations. These activities can also be performed by
smaller, less-advanced vessels, further reducing the total installation cost.

New innovations include tension and length adjustment equipment permanently installed
in the lower portion of the mooring line, e.g. ground chain. The passive side of the ground

31 OMAE2016-54476: Efficient Multi-Line Anchor Systems for FOWTs, Fontana et al 2016

32 NREL Presentation: NOWRDC Symposium, Hall et al 2021

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

chain is connected directly to the adjuster whilst the active side passes through the device
facilitating adjustment. One tensioner can be used for a 3-line system, offering CAPEX savings,
and allows for the use of smaller vessels, thus providing OPEX savings. Overarching safety
benefits are also gained as mooring line adjustments can be made at a distance from the
turbine at any time throughout the life of the system.

Figure 28. Stevtensioner® (top & left) & Stevadjuster® (right) (courtesy of Vryhof)
White dotted line is the active chain and red dotted line is the passive chain

3.4.3 Connectors
As mentioned in Section 3.2, WFO’s O&M Subcomittee identified the need for quick
connection-disconnection equipment and it is likely these will be employed at the top end
of the mooring line. High load ball and taper gripping connectors were first used for quick
mooring connection with anchor piles and SEPLAs on offshore oil and gas structures. Their
employment on FOWTs may remove the need for expensive chain jacks/fairleads and
eliminate the requirement for ROV or diver interventions. Furthermore, their combination
with articulated or universal joints may counteract OPB issues.

Disconnectable turret systems, inspired by FPSO mooring buoy designs, are a simple
method of keeping mooring lines and power cable in suspension whilst FOWTs are off
station. Seabed congestion and potential damage is therefore avoided as double handing,
i.e. set-down and pick-up from the seabed, is not required. This enables shorter power
disconnection times during O&M but also facilitates quick power connections during
installation, which is attractive from an insurer/project developer’s perspective. This
concept could be extended to be a permanent part of the mooring and dynamic cable
system to enable genuine plug-and-play connections, similar to FPSO submerged turret
mooring systems, but may be too costly to become feasible.

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WFO - Mooring Systems for Floating Offshore Wind: Integrity Management Concepts, Risks & Mitigation

Figure 29. Ballgrab® & Uni-Joint Figure 30. DTR System

(courtesy of First Subsea) (courtesy of SBT Energy)

3.4.4 Analysis Software

Analysis software is used to simulate realistic behaviors of a floating wind system in order
to achieve optimal designs of components and their ensuing behavior in shallow water or
deep water conditions. Many companies are developing their own digital solutions that model
different parts of the system and relevant met-ocean conditions (e.g. subsea architecture,
anchorage and electrical equipment), combining cross-disciplinary indicators. The National
Renewable Energy Laboratory (NREL) based in the U.S. has an open-source tool named
OpenFAST which simulates the coupled dynamic response of wind turbines using
hydrodramic, aerodynamic, control system dynamic and structural dynamic models33. All of
these user-friendly solutions aim to help clients find the optimal configuration of a wind farm
or, more appropriately for the current state of the industry, of novel platform concepts before
further commercialization. However, more work is needed to achieve a fully integrated
package for one turbine and its station-keeping system that does not sacrifice on accuracy, let
alone across multiple units. Interfacing software with real-time data from sensors on assets in
the water can help improve the accuracy of structural load and condition modelling, with the
final intention being to accelerate design optimization and validation (Section 3.3.3).

3.4.5 Remote Survey

Floating offshore wind turbines are unmanned installations. Performing inspections on
hundreds of units at distance and in harsh weather conditions poses logistical and safety
challenges. The industry presents an opportunity to develop marine autonomous systems like
Unmanned Surface Vehicles (USV) or Remotely Operated Underwater Vehicles (ROUV or ROV)
to carry out necessary inspection work, namely visual assessment of mooring line and dynamic
cable system integrity, and of marine growth at key interfaces of the line.

33COREWIND D2.1 : Review of the state of the art of mooring and anchoring designs, technical challenges and identification
of relevant DLCs, 2020 (section 6.2)

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3.5 Reporting Systems

The greatest opportunity for improvement is presented when things go wrong and it is
assumed that the application of new designs, technologies and materials in FOWT mooring
systems will result in unanticipated failures via new modes and novel mechanisms. Sharing
details of these events will hugely benefit our nascent industry and speed up the energy
transition. However, commercial and intellectual property concerns present a significant
barrier to achieving this.

Mooring Integrity Management is a theme running throughout this paper and data
analysis is the basis of its success. Procedural-based controls are required for handling
information properly between designers, manufacturers and operators, and transparency is
therefore essential. But this is one area where oil and gas has been less successful: failure rate
data is not in the public domain and since the 2014 OTC 25273 study, information remains
incomplete.

As laid out in Section 2.5, limited insurance cover is available for the floating wind sector
with reduced coverage, increased deductibles and higher premiums compared to bottom-
fixed wind, the latter of which is currently experiencing significant claims. Developers will
need to demonstrate risk mitigations but insurers may decline coverage. Finance could be
difficult to secure on projects using unproven technologies or exhibiting limited track-record.
An early conservative approach is therefore advocated; however, the pressure to reduce LCoE
through innovation and rapid transition to full-scale arrays is the paradox lying at the heart of
the industry.

To overcome this contradiction, the floating wind industry needs to take a radical
approach, but a consensus between all stakeholders is required. To promote the sharing of
information, insurers might consider taking a 'no-fault' approach whereby designers,
manufacturers, developers, installation contractors etc. sign up to an independent reporting
system that shares all mooring integrity management data (not just failure events). The early
phases of any project will be of most interest, with the optimal time to share data being in the
short- to medium-term. In this way, the industry could learn quickly together as anonymised
results may be shared widely, insurers would be protected in the long run, and all would
benefit from lower premium levels. If successful, declining insurance cover in later years could
offset early risks to insurers, as demonstrated by the orange line superimposed on the below
bathtub curve.

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4 Conclusions

Only time will tell which technologies, amongst the current proliferation of FOWT
concepts, may come to dominate our nascent industry. Station-keeping systems will vary
according to foundation type selected, prevailing environmental conditions, geographic
location and regulatory frameworks. There is therefore no ‘one-size-fits-all’ solution.
However, a robust integrity management philosophy and associated process, covering all
stages of the mooring life-cycle and developed in detail during the initial design phase, will be
essential for securing finance and insurance cover across all projects.

In recent years, international classification societies have developed floating wind-specific

standards, but these currently reflect a limited understanding of mooring system behaviour,
requiring harmonisation and on-going development in line with growing operational
experience. Design bases will vary between projects with choices on issues such as line
configuration, materials and anchors shaping procedures relating to installation, repair,
maintenance and decommissioning. As discussed in this paper, considering the trade-offs
between early design choices and later project phases, e.g. impact of the top connection or
anchor on installation, is encouraged to achieve savings in both CAPEX and OPEX whilst also
assuring long-term system reliability. Integrity management during all phases remains critical
for monitoring structural health of the mooring system, assessing its ‘fitness-for-service’, and
determining its current condition versus the as-designed, as-built and as-installed condition.

Redundancy and associated consequence class is an important issue when considering

continuous energy production, i.e. enabling the floater to maintain its position and function
should failure occur. The provision of alternative load paths through additional lines (n+1
concept) is generally considered the preferred option. However, increasing the capacity or
size of equipment (strengthening), effective change-out/sparing strategies, employing load
reduction devices and utilising digital twins to facilitate predictive maintenance may also be
suitable approaches to improving availability. Though not extensively discussed in the
Moorings Subcommittee, the interaction between the mooring system and dynamic power
cable is an area of particular interest and significance in guaranteeing continuous energy
production. The newly formed Cables & Floating Substations Subcommittee, whose inaugural
meeting is scheduled during May 2022, should explore this area in more detail with findings
shared, discussed, and developed across all FOWC Subcommittees.

Innovation is considered key to driving down LCoE but is also a potential constraint on the
exponential growth required to achieve global net zero ambitions. Accelerated technology
qualification to high TRLs at commercial scale is essential. However, developers must provide
sufficient levels of comfort to their investors and insurers by quantifying the additional risk
between LEG 1 and LEG 2, demonstrating technical risk mitigations, and perhaps in some
instances adopting the risk themselves. Early failures in serialised, highly optimised and/or
non-redundant mooring systems may dramatically curtail future developments. Therefore,
initial conservatism is warranted with enhanced inspection and monitoring activities
recommended during early years.

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This paradigm presents a unique opportunity for the floating offshore wind industry to
take a novel approach compared to that which came before, and data sharing is fundamental
to this process. While common failure modes and degradation mechanisms are well
understood from offshore oil and gas experience, there is limited transferability with respect
to floating offshore wind. New threats are either unknown or less well-understood and
consequently not easily prevented by existing IM practices. The greatest opportunity for
improvement presents itself where things go wrong; however, information sharing should not
be limited to failures alone. Moreover, all integrity management data should be made
available so that the whole industry can learn quickly together. Direct measurement through
continual monitoring, periodic measurement or visual inspections are preferred, although
new procedures and digitalisation will complement any developments. Importantly,
intellectual property and commercial contractual constraints also need to be relaxed or
modified to facilitate data sharing. The Committee identified that an independent,
anonymised reporting system which benefits all stakeholders deserves further investigation
and may therefore form part of its future work.

Capability of the supply chain to meet mooring system component demand is another
major challenge for the industry. Currently, there is a limited capacity in the manufacturing
sector for both the forecast volume and dimension of mooring chain. However, the ability for
synthetic rope output to ramp up is deemed relatively feasible which, together with its
perceived operational advantages and growing trend toward compliant mooring systems,
could push for the adoption of alternative layouts, e.g. hybrid buoyant semi-taut spreads with
smaller footprints. Furthermore, implementing an n+1 approach may provide an opportunity
to manufacture smaller lines with consequent benefits to handleability and installation.
However, trade-offs later in life should be considered, for instance the monitoring needs that
would likely increase to cover the number of lines. Finally, the importance of working with
experienced suppliers that have equipment/technology track record can pose a challenge to
markets implementing local content targets. Building localised floating wind supply chains will
require large investments and sustainable knowledge transfer mechanisms from established
industry players to boost the development of suitable, local production facilities.

The nascent floating offshore wind industry stands at a crossroads. Rapid transition from
small-scale/demonstrator projects to commercial scale arrays is urgently required to achieve
global net zero ambitions and reduce LCoE. Lessons derived from oil and gas experience will
be important, but transferability is limited and therefore a unique opportunity to take a novel
approach arises. Innovation will be key but early failures in serialised systems may impact
project finance and insurance availability, potentially restraining growth. Initial work
conducted by the Moorings Subcommittee has determined the Integrity Management
process’ holistic, iterative characteristics can support the industry’s path into technological
maturity through the rigorous monitoring of risks and associated implementation of
mitigation measures at all project phases alongside an improved system for data-
sharing. Future efforts will focus on areas of particular interest and significance, supporting
our main Chair’s earlier call to “…bring even more relevant information to the market.”

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Appendix - Governing Standards for FOW

Tables courtesy of ORE Catapult’s Floating Offshore Wind Centre of Excellence

IEC TS 61400-3-2 Framework

ABS 195 Framework

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BV NI572 Framework

LR Guidance Note Framework

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DNV-ST-0119 Framework

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