deliverable 4.3: report on suitability of assessment ... · figure 5-1: micropile, courtesy of...

D8.1 Scientific and Technical coordination Guidelines Lead partner: Norwegian Marine Technology Research Institute

(MARINTEK)

Contributing partners: The University of Exeter (UNEXE), University College Cork (UCC), Tension Technology International (TTI) Ltd, Sandia National Laboratories (SNL), DBE – DEME Blue Energy nv, WavEC – Offshore Renewables

Authors: Madjid Karimirad, Kourosh Koushan, Sam Weller, Lars Johanning, Jon Hardwick, Marco Guerrini, Stephen Banfield, Edward N Matteo, Jan Goormachtigh, Alex Raventos

This project has received funding from the European Union’s Seventh Programme for research, technological development and demonstration under grant agreement No 608597

Deliverable 4.3: Report on suitability of assessment functions to validate novel mooring and foundation

component designs

Deliverable 4.3 – Report on suitability of assessment functions to validate novel mooring and foundation component designs

2

Doc: DTO_WP4_ECD_D4.3 Rev: 3.0 Date: 25.07.2014

D4.3: Report on suitability of assessment functions to validate novel mooring and foundation component designs

Project: DTOcean - Optimal Design Tools for Ocean Energy Arrays

Code: DTO_WP4_ECD_D4.3

Name Date

Prepared Work Package 4 07/07/14

Checked Work Package 9 18/07/14

Approved Project Coordinator 25/07/14

The research leading to these results has received funding from the European Community’s Seventh Framework Programme under grant agreement No. 608597 (DTOcean). No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form – electronic, mechanical, photocopy or otherwise without the express permission of the copyright holders. This report is distributed subject to the condition that it shall not, by way of trade or otherwise, be lent, re-sold, hired-out or otherwise circulated without the publishers prior consent in any form of binding or cover other than that in which it is published and without a similar condition including this condition being imposed on the subsequent purchaser.


3



4


Abstract

It is the purpose of this document to evaluate the suitability of existing component assessment

functions for marine renewable energy (MRE) array foundation and mooring applications. In order to

inform the development of the DTOcean design tool, particular attention is given to i) the

introduction of new components made from well-established or novel materials/construction, and ii)

capabilities towards reliability and cost prediction. Whilst it is the role of WP4 to address a broad

range of components for array foundations and mooring configurations, particular attention in this

deliverable is given to corrosion effects, grouts and synthetic materials. For these areas indicative

cost and reliability values are provided. However, it is found that consistent approaches to assessing

cost and reliability do not exist beyond simplistic metrics (i.e. component unit costs) either due to a

lack of relevant data or the complexity of inter-related aspects. It will be the role of tasks 4.5-4.7 to

investigate reliability, economics and environmental aspects to a greater level of detail for inclusion

of methodologies into the Design Tool.


5


TABLE OF CONTENTS

Chapter Description Page

1 INTRODUCTION ........................................................................................................................................ 9

2 GROUTING .............................................................................................................................................. 10

2.1 BACKGROUND ................................................................................................................................................... 10

2.1.1 Material....................................................................................................................................................... 11

2.1.2 Grouting plant ............................................................................................................................................. 11

2.1.3 Example Installation procedure ................................................................................................................... 12

2.1.4 Other directives ........................................................................................................................................... 12

2.2 CONSIDERATIONS FOR SPECIFICATION .............................................................................................................. 12

2.2.1 Design and classification .............................................................................................................................. 12

2.2.2 Improvement of grouted connections .......................................................................................................... 13

2.2.3 Strength of a grouted connection ................................................................................................................ 15

2.2.4 Degradation and environmental exposure ................................................................................................... 16

2.3 COST AND RELIABILITY ASSESSMENT ................................................................................................................. 17

2.3.1 Costs ............................................................................................................................................................ 17

2.3.2 Quality control............................................................................................................................................. 18

2.3.3 Alternative connections ............................................................................................................................... 18

3 SYNTHETIC ROPES ................................................................................................................................... 20

3.1 MATERIALS AND CONSTRUCTIONS .................................................................................................................... 20

3.2 DESIGN AND CLASSIFICATION ............................................................................................................................ 23

3.2.1 Strength ...................................................................................................................................................... 23

3.2.2 Fatigue performance ................................................................................................................................... 24

3.2.3 Axial stiffness .............................................................................................................................................. 25

3.2.4 Axial damping .............................................................................................................................................. 26

3.2.5 Considerations for the design of MRE mooring systems ............................................................................... 26

3.3 DEGRADATION .................................................................................................................................................. 29

3.4 COST AND RELIABILITY ASSESSMENT ................................................................................................................. 30

3.4.1 Reliability experiences from the oil and gas industry ................................................................................... 32

4 CORROSION ............................................................................................................................................ 35


6


TABLE OF CONTENTS

Chapter Description Page 4.1 BACKGROUND ................................................................................................................................................... 35

4.2 DEGRADATION MECHANISMS ........................................................................................................................... 37

4.2.1 Hydrogen Induced Stress Cracking ............................................................................................................... 37

4.2.2 CO2-corrosion .............................................................................................................................................. 38

4.2.3 O2-corrosion ................................................................................................................................................ 38

4.2.4 Microbiologically Induced Corrosion (MIC) Corrosion fatigue ....................................................................... 39

4.2.5 Corrosion fatigue ......................................................................................................................................... 39

4.3 COST AND RELIABILITY IMPLICATIONS ............................................................................................................... 40

4.4 CONCRETE ......................................................................................................................................................... 41

4.4.1 Metals ......................................................................................................................................................... 42

4.4.2 Protective Coatings ...................................................................................................................................... 44

5 NOVEL COMPONENTS ............................................................................................................................. 49

5.1 MARINE MICROPILE FOUNDATIONS .................................................................................................................. 49

5.2 THE EXETER TETHER ........................................................................................................................................... 50

5.3 BAG ANCHORS ................................................................................................................................................... 51

5.4 CONNECTORS .................................................................................................................................................... 52

6 CONCLUSIONS ........................................................................................................................................ 54

7 BIBLIOGRAPHY ........................................................................................................................................ 56

8 ACRONYMS ............................................................................................................................................. 61


7


TABLES INDEX

Description Page

Table 3-1: Selected properties of several synthetic fibre materials (values from (McKenna, HA, Hearle, JWS. and O’Hear, N,

2004)). Steel is included for reference. Note: the modulus of nylon is approximately 15% lower when wet. Tex is a measure of

weight per unit length (units: g/km) ......................................................................................................................................... 22

Table 3-2: Partial safety factors for synthetic ropes from DNV-OS-E301 Position Mooring (DNV, Offshore Standard – Position

Mooring. DNV-OS-E301, 2010) for two consequence criteria (CC) ........................................................................................... 24

Table 3-3: Offshore certification guidance and recommended practices for synthetic fibre ropes ........................................... 28

Table 3-3: Cost comparison carried out by Ridge et al. (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010) of three hypothetical

catenary mooring systems located in d = 50 m water depth. Buoyancy of the buoys is specified in tonnes and drag embedment

anchors are specified. ............................................................................................................................................................... 31

Table 4-1: Internal and external corrosion mechanisms in a subsea oil and gas production environment (DNV, MATERIAL RISK

- AGEING OFFSHORE, 2006). ..................................................................................................................................................... 36

Table 4-2: Costs for coatings and anodes in the submerged zone, all costs in k€ (Knudsen, 2010). ........................................ 41

Table 4-3: Coating specification outside and inside for steel towers for wind turbines in different wind parks given by Hempel

(Knudsen, 2010) ........................................................................................................................................................................ 47

Table 4-4: Corrosion protection for Hywind offshore wind turbine and the Sharingham Shoal offshore wind park ................. 48

Table 4-5: Corrosion protection systems for the five last steel jackets produced by Aker Solutions, Verdal ............................ 48


8


FIGURES INDEX

Description Page

Figure 2-1: Monopile types in terms of axial load transfer mechanism (A: plain pipe; B: connection with shear keys; C: shear

keys only in the center of the connection). .............................................................................................................................. 14

Figure 2-2: Conical shape connections, DNV ............................................................................................................................ 15

Figure 2-3: Alternative connections .......................................................................................................................................... 19

Figure 3-1: Indicative specific stress-extension curves for various synthetic fibres; aramid, steel, nylon (PA), polyester (PET) and

gel spun high modulus polyethylene (HPPE) (graph adapted from (McKenna, HA, Hearle, JWS. and O’Hear, N, 2004)). ........ 21

Figure 3-2: Load-extension behaviour of a new nylon mooring rope sample subjected to 10 cycles of bedding-in during the tests

reported in (Weller SD, Davies P, Vickers AW, and Johanning, L, 2014) ................................................................................... 22

Figure 3-3: a) Typical rope construction hierarchy (image adapted from (Flory JF, Leech CM, Banfield SJ and Petruska DJ, 2005)),

b) nylon parallel-stranded construction (Weller SD, Davies P, Vickers AW, and Johanning, L, 2014) and c) schematic of Bexco

double-braid rope (image source: http://www.bexco.be/) ....................................................................................................... 23

Figure 3-4: Fatigue results for several mooring components (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010). Dashed lines

indicate extrapolated values ..................................................................................................................................................... 25

Figure 3-5: 100 year storm wave loading on a renewable device ............................................................................................. 27

Figure 4-1: Corrosion process, https://www.boundless.com/readings/3151/ .......................................................................... 37

Figure 4-2: Corrosion effects on fatigue life, http://www.corrosionclinic.com/types_of_corrosion/Corrosion%20Fatigue.htm40

Figure 4-3: Illustration of concrete corrosion in offshore environment, .................................................................................... 42

Figure 4-4: Cathodic protection, Courtesy of Deepwater Corrosion Services Inc. http://www.cathodicprotection101.com/ ... 43

Figure 4-5: Left: corrosion and break-up of IWRC of 76 mm ungalvanized MODU mooring rope after five years' service; right:

IWRC of 90 mm galvanised MODU mooring rope after 7 years (C.R.Chaplin, A.E. Potts and A. Curtis, 2008) .......................... 45

Figure 5-1: Micropile, Courtesy of Marine Micropile Technology Group, http://www.marinemicropile.com .......................... 50

Figure 5-2: Deployment of the SWMTF with two Exeter Tethers (left, foreground) .................................................................. 51

Figure 5-3: Bag anchor .............................................................................................................................................................. 52

Figure 5-4: Triplate connector Figure 5-5: Inline or end connector ...................................................................................... 53

Figure 5-6: Generic range of mooring connectors Figure 5-7: SDSS Inline connectors with pins...................................... 53


9


1 INTRODUCTION

The specification of suitable foundation or mooring systems for the station keeping of marine

renewable energy (MRE) devices is one of the important objectives of WP4 in the DTOcean project.

The reliability of components is pivotal key to the functionality of the mooring or foundation system

and the continued availability of all devices in the array. These subsystems represent a significant

proportion of the lifecycle costs of offshore wave and seabed mounted tidal energy arrays

(estimated to be approximately 6% and 14% respectively (SI-Ocean, 2013)) and hence opportunities

to reduce costs must be sought in order for arrays to be commercially viable. The focus of this

report is the cost and reliability implications of several MRE mooring and foundation topics: 1)

corrosion 2) grouting systems 3) synthetic ropes and 4) novel components.

Although the marine renewable industry can utilise existing knowledge regarding materials an

operational techniques from more mature offshore industries (i.e. the oil and gas sector), this

information is not fully transferrable to the marine renewable sector. Therefore research and

appraisal of component or procedure suitability are both required. The cost, environmental impact

and reliability of a proposed large scale deployment of MRE devices all require close scrutiny

because at array scale the implications of each inter-related factor could be positive (i.e. cost

reductions due to bulk purchasing) or negative (i.e. unscheduled maintenance costs incurred due to

low reliability). The aim of this report is to evaluate the suitability of assessment functions to

validate novel mooring and foundation component designs. Various material and design assessment

tools for a broad range of array foundations and moorings are investigated. Particular attention is

given to the introduction of new components made from established or novel materials and

construction techniques and to their capabilities towards improving the reliability and reducing the

costs of MRE mooring and foundation systems.

In Section 2 the technique of grouting which is largely employed in terrestrial and maritime civil

engineering works is described with subsections dedicated to the material characteristics as well as

degradation due to environmental exposure. Synthetic ropes have a long track record of use in the

oil and gas industry. Their use in MRE mooring systems is discussed in Section 3. Materials along with

design approaches and reference standards are the key topics of this section. Section 4 is meant to

derive a ‘best practice’ with regards to monitoring and mitigation of corrosion and degradation

process for metal and concrete structural elements caused by chemical and biological process. In

each of the aforementioned sections existing approaches to assess cost and reliability are

introduced. The use of novel components in the MRE industry with regard to mooring and

foundation systems is addressed in Section 5. Conclusions and final remarks are drawn in Section 6.


10


2 GROUTING

2.1 Background

The technique of grouting is commonly used for offshore installations. Examples are grouted steel

connections or sleeves and both have been used in both steel and concrete structure applications.

Also, connections between the foundation and (rocky) soil can be made through grouting the pile(s)

and the drilled sockets. Both pin piles (small diameters) and monopiles (large diameters) are to be

considered.

More recent examples in offshore marine applications include drilled and grouted piling, as well as

the concrete grouting connection between the pile and the transition piece for wind turbines.

Although the bending moments from wind and waves were always considered as important design

parameters, it was found that the axial holding capacity was significantly lower than previously

assumed due to the effect of larger diameters of monopiles, the lack of control of tolerances and the

abrasive wear of the grout due to the sliding of contact surfaces when subjected to large bending

moments. This resulted in reported failures (DNV.GL, 2011) of the grouted transition sections for

wind turbines, causing them to slip. Typical failure modes include disbonding, cracking, wear and

compressive failure.

The purpose of grouting is to establish a sound and reliable connection between two bodies. In case

of an anchor application, the grout body adheres to the pile and to the anchoring medium and the

pile capacity typically depends on the bond strength between the grout and soil/rock interface.

Drilling and grouting is essentially identical to the method used to set a casing for an oil well. A hole

of somewhat larger diameter than the pile is drilled to the proper depth using rotary drilling tools

and is cleaned out by pumping seawater through the drill string. The pile is placed over the drill

string and lowered into the hole. Portland cement grout is pumped down the drill string and forced

up outside of the pile to fill the annular void and bond the pile to the soil. The interior of the pile is

filled with grout as the drill string is withdrawn. Piles up to 8 feet in diameter have been placed in

water depths in excess of 200 m by drilling and grouting. For small piles set in rock, either cement or

epoxy grout can be used.

It is important to have a system to develop a remotely controlled grouting procedure that can be

applied to deep water grouted pile anchor installations with emphasis on a grout delivery control

system.


11


The requirements and technologies for a Quality Control and Certification Procedure to validate

deep underwater grouted pile anchor installations and conformance with identified environmental

concerns should be documented.

The grouting procedure and the qualification pull test procedure were identified as the key

technology areas that required development to advance the concept. An extensive technology

review of currently available grouting methodologies; both terrestrial and marine, to identify

promising grout chemistries and grouting procedures has been carried out. For the pull test, the plan

was to use the concept validation tests as an opportunity to develop and prove a pull test apparatus

and procedure scalable to the production application. The pull out capacity (Tf) of anchorage is

dependent upon the strength of the material mass and is limited in BS8081 to a grout/rock bond

stress of 4N/mm2 for strong rock. Similarly, the grout/tendon bond stress is limited in to 2N/mm2 for

deformed bar.

2.1.1 Material

Materials which may be used for grouted connections include:

Portland cement grouts with or without inert fillers mixed preferably with fresh water,

although seawater may be used. There may be special circumstances where the use of

seawater is undesirable because of corrosion and other durability effects.

Fresh water/high alumina cement grouts providing that, to take account of the conversion

process, the design is based on the minimum strength appropriate to the curing

temperature, service temperature and water: cement ratio.

Admixtures may be used to improve properties of the slurry or set grout provided that it is

established that they have no harmful effect on the performance of the connection. Calcium

chloride or admixtures containing significant levels of chloride ions should not be used.

2.1.2 Grouting plant

A typical grouting plant consists of the following items:

- a mixing unit

- concrete pumps

- waste pans

- flexible grout hoses

- tool container (with spares, reduction pipe, stinger, etc.)


12


2.1.3 Example Installation procedure

The general installation concept for the monopile foundation installation works is summarized as

following:

Upend and lift drilling conductor

Lowering of drilling conductor onto the seabed; through the installation frame

Fixating the conductor into the seabed by means of an hydraulic oscillator (+/- 0.5m

penetration)

RCD boring of socket up to required depth

Upending and lifting of monopile foundation

Installation of monopile foundation within the conductor

Grouting of monopile annulus

Loosen conductor by oscillator

Extract conductor

2.1.4 Other directives

In case of pile foundation grouting, the grout should be injected at the lowest point of the annulus

so that any fluid present is completely displaced. Reliable means of ensuring complete filling of the

annulus with sound grout should be incorporated, such as a) provision for samples of material at the

top of the annulus to be returned to the surface by piping or by divers, or b) the provision of proven

remote monitoring devices at the top of the annulus.

Particularly for monopiles, it is recommended that an attachment (e.g. perforated blanking plate)

will be in place at the bottom section to facilitate quick formation of a grout plug; in order to reduce

the required grout volume inside the monopiles.

2.2 Considerations for specification

2.2.1 Design and classification

The literature review identified that certain key grout attributes would be needed for marine

foundation applications, namely:

Non-shrinkage (expansive properties beneficial)

Good pumpability

Early strength development


13


Good strength (minimum unconfined compressive strength of over 6,000psi / approx.

40N/mm2 at 28 days is specified as an example)

Free of chlorides or other salts (high resistance to chemical attack when cured)

It was found that such grouts typically comprise a blend of Ordinary Portland Cement (OPC),

selected fillers, plasticizers, expansion additives and waterproofing admixtures. For subsea

placement, the addition of anti-washout properties was also suggested to be beneficial. Finally it

was identified that manufacturers would have to be consulted to ensure that none of the chemicals

or additives to be used would be harmful to the marine environment. A detailed grout specification

was prepared for the project, covering grout properties, chemical composition and also testing

requirements. Due to quality control issues and the relatively small volumes of grout required for

each anchor it was recommended that pre-blended bagged grout be used, and mixed using potable

water. This ensures that the Quality Assurance/Quality Control testing will correlate with

manufacturer’s recommendations and international design standards. For mixing the grout, a high

speed, high shear colloidal grout mixer was specified. The high-speed shearing action of a colloidal

mixer achieves greater hydration of the cement by wetting each individual particle, and mixing time

is significantly lower than conventional paddle mixers. This type of mixer provides an extremely

efficient and rapid means of producing high quality grout. Additional developments are suggested

investigating the use of grouts compatible with seawater.

2.2.2 Improvement of grouted connections

In order to increase the strength of grouted connections, some measure can be taken as illustrated

below and applied to transition piece connections:

Grouted connections with shear keys (DNV, Certification of Grouted Connections for Offshore Wind

Turbines., 2013)

The new knowledge is also expected to influence the design of large diameter grouted connections

with shear keys. Shear keys are circumferential weld beads on the outside of the monopile and the

inside of the transition piece in the grouted section. The shear keys’ purpose is to increase the sliding

resistance between the grout and steel so that no settlement occurs. The existing design standards

for such connections are based on limited test data for alternating dynamic loading. Before this

solution can be recommended, a design practises for shear keys should be developed and properly

incorporated in design standards.


14


Figure 2-1: Monopile types in terms of axial load transfer mechanism (A: plain pipe; B: connection with shear

keys; C: shear keys only in the center of the connection).


15


DNV initiated a complementary joint industry project with the aim of updating existing knowledge of

and design practices for grouted connections with shear keys. DNV JIP is now complete and the

results have been published (Inge Lotsberg, Andrzej Serednicki, Håkon Bertnes and Andreas Lervik,

2012) and results of JIP have been included in latest DNV standards (Design of Offshore Wind

Turbine Structures DNV-OS-J101).

Conical shaped connections (DNV, Summary Report from the JIP on the Capacity of Grouted

Connections in Offshore Wind Turbine Structures, 2010)

Based on the DNV JIP, a design practise to account for large dynamic bending moments on

monopiles has been developed using conical shaped connections. According to this, the monopile

and transition piece are fabricated with a small cone angle in the grouted section.

Figure 2-2: Conical shape connections, DNV

2.2.3 Strength of a grouted connection

The following have been shown to be the principal factors affecting the strength of a grouted

connection:

· grout compressive strength and elastic modulus

· tubular and grout annulus geometries

· outstand and spacing of mechanical shear connectors

· grouted length to pile diameter ratio

· surface condition of tubular sections

· long term grout shrinkage or expansion.


16


It is strongly recommended that mechanical shear connectors are used, since their presence can

result in connection strengths of several times that of plain pipe connections with resulting economy

for the complete structure. The use of mechanical shear connectors increases the reliability of the

connection and eliminates the effect of long term grouting shrinkage on the connection capacity.

Mechanical shear connectors may take the form of continuously welded bars or weld beads

attached to the steel surfaces in contact with the grout and may be arranged in hoop or helical

formation. Other forms of shear connectors require special consideration.

Where the design of the grouted connections takes account of the presence of shear connectors, the

following recommendations apply:

Shear connectors should be present on both the pile and sleeve surfaces which are in

contact with the grout.

The shear connector spacing should be uniform along the length of the connection.

The outstand and spacing of shear connectors on the sleeve and pile should be the same. If

this is not the case then the characteristic bond strength should be assessed both for the

outer surface of the pile and the inner surface of the sleeve and the lower value used to

calculate the connection capacity.

For driven piles, shear connectors should be applied to sufficient length of the pile to ensure

that, after driving, the part of the pile in contact with the grout has shear connectors.

Shear connector cross-section and welds on each grout/steel interface should be designed

to transmit the total load applied to the grouted connection.

2.2.4 Degradation and environmental exposure

A review of cementitious materials in the literature indicates that the greatest chemical threat to

cement and concrete in the maritime environment is sulphate attack, which owes to the presence of

magnesium sulphate in seawater (Lea, 1970) (Taylor, 1990). This is especially pronounced in

warmer, tropical waters where the kinetics of degradation are faster. Chemical leaching of

cementitious material in seawater can be enhanced when carbon dioxide levels are elevated

(carbonation), which could be the by-product of organic matter decay or microbial activity. An

elevated carbon dioxide condition primarily occurs in sheltered bays and estuaries so may be of

minimal concern for offshore locations. Sulphate resistant cement formulations - as used in oilfields

and other subsurface engineering applications, can be employed at an economically-feasible manner

to solve the sulphate attack. Understanding the conditions that would lead to elevated carbon

dioxide is an area of potential concern that may need special attention with respect to siting of a

MRE device. Overall, as suggested elsewhere in this report, the proper selection of cement


17


formulation and design (i.e. controlling permeability) can eliminate the majority of causes for

chemical attack.

Another important mode of chemical attack pertains to cement in contact with steel. When in

contact with cement, steel is passivated from corrosion due to the hyperalkaline nature of cement

pore waters. However, exposed areas of steel, or steel elements in contact with chemically leached

cement, can corrode, which, in turn, can lead to mechanical degradation. This is a well-documented

ailment of steel-reinforced concrete (Taylor, 1990) in civil engineering applications (mitigation steps

are discussed in Section 4.3.1), and it is recommended that this attack mechanism be identified as an

area of concern, owing to the fact that the generic design concept allows for a variety of steel-

cement interfaces to be incorporated into the foundation.

A review of the literature also indicated freeze thaw as a potential origin of mechanical degradation

of cement in the maritime environment (Lea, 1970). Structures located in northern latitudes and

periodically exposed, e.g. due to tidal variations, are most susceptible to this mode of degradation.

In general, cement/concrete structures which are completely submerged are at very low (or zero)

risk of suffering freeze thaw attack. Overall, choosing the appropriate cement will be the most

important safeguard with the broadest applicability. However, special concern should be given to

steel/cement interfaces, as well as conditions were microbial activity or decay of organic-rich matter

may produce elevated carbon dioxide levels.

2.3 Cost and reliability assessment

2.3.1 Costs

The expenditures of grouting activities and material supply are very case specific. However, a few

cost drivers can be identified:

Grout volume

Type of connection

o Grout losses (mainly due to spill)

o Pile dimensions (diameter).

Installation time

Grouting speed: of 6 m³/h (order of magnitude) but will be affected by different factors

o Weather conditions: (mainly wave and current restrictions) should allow carrying

out the grouting activity continuously.

o Water depth: has its influence on the total grouting time.


18


Type of equipment

o The capacity of the grouting equipment,

o The type of support vessel,

o The installation procedure.

To give an indication of the cost of grout materials, a quick survey1 determined that they range from

€10 - €150 per ton with the price dependent on the material grade specified. The highest price refers

to grouts which have high compressive strengths (greater than 100MPa) and at the lower end of the

range are grouts based on Portland cement with lower compressive strengths.

2.3.2 Quality control

During the grouting of each connection, samples of grout should be taken from randomly selected

batches. The rate of sampling should take account of the nature of the work. At least four samples,

each of three cubes, should be taken for each connection. One cube for each sample should be

tested to assess compliance (usually at 28 days). The remaining cubes may be tested at earlier ages

to indicate the grout quality. Until tested the specimens should be subjected to a curing regime

representative of the curing conditions of the grouted connection. i.e. underwater and at the

appropriate seawater temperature (DNV, Design of Offshore Wind Turbine Structures, 2011).

Strength compliance can be assumed if no test result in each set of four is below the specified

characteristic grout compressive strength. In the event of non-compliance the action taken should

have due regard for the nature and degree of non-compliance and the implications for safety.

2.3.3 Alternative connections

Due to degradation of grouted connections, recently bolted connections came more and more in the

picture to provide a more sustainable solution in case of connecting a transition piece to a monopile.

Although, with the grouted connection it is possible to correct non-verticalities up to 0.5° and the

grout also serves as barrier to avoid water ingress. Nevertheless, bolted connections are for this type

of connections more and more favourable due its robustness. Moreover, non-verticalities are also

possible to correct with a circular correction plate, to be mounted on the upper flange of the

monopile and oriented according to its horizontal deviation.

1 Costs obtained in July 2014 by GeoSea, part of the DEME Group


19


Figure 2-3: Alternative connections


20


3 SYNTHETIC ROPES

Use of the synthetic mooring ropes began in the 1980s with initial trials of aramid ropes conducted

for Mobile Offshore Drilling Units (MODUs). As the offshore oil and gas industry moved to deeper

water exploration sites, cost and reliability requirements became pivotal to the development of

economic and reliable mooring systems. With a notable number of permanent mooring system

failures caused by the failure of steel components (Noble-Denton, 2006) (Ma, K-t, Duggal A,

Smedley, L'Hostis D and Shu H, 2013), synthetic ropes offer a low cost, low weight, compliant and

durable alternative and they are widely used for a range of temporary and permanent mooring

applications (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010) (da Costas Mattos, HS and Chimisso,

FEG, 2011) (Flory, J and Banfield, SJ, 2006). The selection of synthetic ropes over steel components

(e.g. chain and wire) has been identified as a potential way of reducing capital costs (Carbon Trust

and Black & Veatch, 2011) whilst improving the reliability of mooring systems. Several device

developers are known to be using or considering using synthetic ropes, including the CETO wave

energy converter (WEC) developed by Carnegie Wave Energy.

Synthetic rope mooring systems are become attractive for offshore technology due to the following

factors:

Reduced weight

Easier installation

Compliance

Favourable performance in extreme loading conditions

Favourable fatigue performance

Synthetic ropes have become an accepted alternative to chain and steel wire rope mooring lines in

recent years. At present, polyester fibre is the most widely used synthetic fibre for this purpose. High

modulus polyethylene (HMPE) is an alternative to polyester, with many favourable properties.

During recent years (Ridge, Banfield Mackay 2010) nylon fatigue life has been increased to such an

extent that it can be used for permanent mooring systems.

3.1 Materials and constructions

A variety of materials feature in commercially available synthetic ropes, however for brevity only the

main types which are likely to be used by the MRE industry are summarised: nylon (polyamide, PA),

polyester (PET), aramid and high modulus polyethylene (HMPE). Polyester is currently the most

widely used material for permanent mooring systems. Referring to Table 3-1, the strength per unit

weight of these four materials is significantly higher than steel. The low weight per unit length


21


means that they are also easier to handle and install and therefore the hanging weight or pretension

of the mooring line is lower. Synthetic materials extend to a greater level than steel before failure

(Table 3-1 and Figure 3-1) and it is this compliance which is the one of the main advantages of using

these materials in mooring ropes. Stiffer materials such as HMPE and aramid tend to be used for

taut-mooring configurations, with polyester and nylon used for applications requiring greater

compliance including permanent mooring systems and hawser. The ability to absorb energy during

dynamic loading can reduce the magnitude of peak loads (e.g. (Kirrane P, Fabricius P and Morvan R,

2010)) and this is due to the viscoelastic or hysteresis response of these materials (Chailleux E and

Davies P, 2003) (Flory JF, Leech CM, Banfield SJ and Petruska DJ, 2005) (Weller SD, Davies P, Vickers

AW, and Johanning, L, 2014) (e.g. Figure 3-2). Under the application of a constant load synthetic

materials will extend or creep. Once load is removed, extension recovery takes place and these two

processes are either immediate or delayed. The response of these materials is therefore dependent

on load history, the magnitude of applied load and in the case of dynamic loading, load amplitude.

Loading rate is generally not important except for the first few loadings in the rope life and therefore

response sensitivity to loading rate is negligible at the load frequencies of interest for moorings.

Figure 3-1: Indicative specific stress-extension curves for various synthetic fibres; aramid, steel, nylon (PA),

polyester (PET) and gel spun high modulus polyethylene (HPPE) (graph adapted from (McKenna, HA, Hearle,

JWS. and O’Hear, N, 2004)).


22


Material Density (g/cm3) Modulus (N/tex, GPa) Tenacity (mN/tex) Break extension (%)

Steel

HMPE

Aramid

PET

PA6

7.85

0.97

1.45

1.38

1.14

20, 160

100, 100

60, 90

11, 15

7, 8

330

3500

2000

820

840

2(2)

3.5

3.5

12

20

Table 3-1: Selected properties of several synthetic fibre materials (values from (McKenna, HA, Hearle, JWS. and

O’Hear, N, 2004)). Steel is included for reference. Note: the modulus of nylon is approximately 15% lower when

wet. Tex is a measure of weight per unit length (units: g/km)

Figure 3-2: Load-extension behaviour of a new nylon mooring rope sample subjected to 10 cycles of bedding-in

during the tests reported in (Weller SD, Davies P, Vickers AW, and Johanning, L, 2014)

In addition to material properties, construction also has a significant influence on rope performance,

as discussed in (McKenna, HA, Hearle, JWS. and O’Hear, N, 2004). In Figure 3-2 the response of the

rope to initial loading is clearly different from subsequent loading cycles and the resulting

permanent elongation is due to the viscoplastic response of the material as well as rearrangement of

the rope structure. Most commercially available constructions are hierarchical starting from

individual fibres which are combined to form yarns, yarn assemblies and strands (Figure 3-3a).

2 Yield point of steel.


23


Parallel-stranded ropes tend to be used for high load applications and comprise strands assembled

into subropes which are typically covered in a protective jacket (e.g. Figure 3-3b). Plaited and

braided constructions are also used (e.g. Figure 3-3c).

Figure 3-3: a) Typical rope construction hierarchy (image adapted from (Flory JF, Leech CM, Banfield SJ and

Petruska DJ, 2005)), b) nylon parallel-stranded construction (Weller SD, Davies P, Vickers AW, and Johanning, L,

2014) and c) schematic of Bexco double-braid rope (image source: http://www.bexco.be/)

3.2 Design and classification

3.2.1 Strength

The ability of a rope to withstand the expected loaded conditions is clearly of prime importance to

keep the device on station. The minimum break load (MBL) of commercially available rope is readily

available from the manufacturer and is based on tension-tension tests in which the rope is loaded

until failure (e.g. (DNV, 2013)). Whilst preliminary design guidelines have been developed for the

MRE devices (DNV, 2012) (IEC, 2014), the factors of safety which are applied on top of the MBL to

provide an adequate margin of safety are ultimately based on existing offshore guidance (e.g. (API,

2005)) developed for the oil and gas industry. Use of conservative factors of safety is potentially

onerous for MRE array developments because the consequence of mooring component failure will

be less severe than for oil and gas equipment.

Several scenarios are utilised in (DNV, Offshore Standard – Position Mooring. DNV-OS-E301, 2010) to

determine the required strength of mooring components3 (Sc), including Ultimate Limit State (ULS)

3 The statistical uncertainty of strength characteristics based on test statistics has to be accounted for (IEC, 2014)

http://www.bexco.be/


24


and Accident Limit State (ALS) scenarios is calculated using the following equation based on mean

and dynamic loadings (Tc-mean and Tc-dyn) and using the partial safety factors listed in Table 3-2:

When characteristic strengths are not available, Sc is determined from the minimum break strength

of new components (Sc = 0.95Smbs). Different approaches to strength calculation are taken in Bureau

Veritas and Norwegian guidelines (BV, 2012) (NORSOK, 2009).

Mean tension factor

(γmean) ULS, ALS

Dynamic tension

factor (γdyn)

ULS, ALS

Dynamic (CC1)

Dynamic (CC2)

Quasi-static (CC1)

Quasi-static (CC2)

1.10, 1.00

1.40, 1.00

1.70, 1.10

2.50, 1.35

1.50, 1.10

2.10, 1.25

1.70, 1.10

2.50, 1.35

Table 3-2: Partial safety factors for synthetic ropes from DNV-OS-E301 Position Mooring (DNV, Offshore

Standard – Position Mooring. DNV-OS-E301, 2010) for two consequence criteria (CC)

3.2.2 Fatigue performance

Mooring components undergo cyclic loading which will eventually lead to failure through fatigue and

this could potentially be an issue for MRE devices undergoing highly dynamic motions, particularly

for steel components. There are two main test procedures which have been developed to quantify

the fatigue life of synthetic ropes and rope yarns. The thousand cycle load level test (TCLL) was

originally developed for nylon hawsers and includes several load levels, starting at a load range of 2-

50% MBL (International Marine Forum, 2000). The fatigue life of individual yarns is determined

through yarn-on-yarn abrasion tests (Cordage Institute, 2009) with relevant standards for

performance (Cordage Institute, 2013). For fatigue life analysis, (including Fatigue Limit State (FLS)

calculations) it is possible to obtain fatigue data based on standard testing practices from published

literature (e.g. Figure 3-4).


25


Figure 3-4: Fatigue results for several mooring components (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010).

Dashed lines indicate extrapolated values

3.2.3 Axial stiffness

Due to the complex behaviour associated with synthetic ropes, modelling of rope axial stiffness (EA,

units: N) is non-trivial. Characteristic performance curves have been developed based on

experimental data such as the following formula to calculate the stiffness of polyester (Cordage

Institute, 2009):

: Polyester rope instantaneous stiffness. : Static stiffness

: Mean load stiffness coefficient. : Varying load stiffness coefficient

: Mean load level. : Amplitude of dynamic loading

In this formulation it can be seen that the stiffness of the rope depends on a combination of the

static stiffness, mean load level and dynamic load range. To a much lesser extent creep and

constructional elongation affect the elastic response. Providing a sufficient installation tension can

be applied to the line, the majority of creep and certainly all the constructional effects can be


26


removed. If the installation tension is higher than the maximum tension during service life, then all

the primary creep and constructional effects are removed. Secondary creep is linear with log time

and for most materials is very small. However, the cost of installation will increase with higher

installation tensions as larger capacity equipment will be required. With continued dynamic loading

the stiffness of polyester rope increases until a certain maximum stiffness is reached, a plateau

which depends on mean load and dynamic loading amplitude. The plateau level is the reference

stiffness for design. In realistic extreme environmental conditions, the plateau is reached within an

hour of a storm event occurring (Casey, NF and Banfield, SJ, 2005). For polyester rope, this

behaviour results in dynamic stiffness from 2 to several times the static stiffness. Failure to account

for this behaviour will inevitably yield inaccurate line tension and device offset predictions, which

could lead to device impact in the case of an array of closely spaced devices.

In order to more accurately simulate the static-dynamic elongation behaviour of fibre rope 2-and 3-

slope models were developed by the American Bureau of Shipping (ABS, Guidance Notes on the

Application of Fiber Rope for Offshore Mooring, 2011). In the 2-slope model the response of the

rope to initial loading up to the mean load is based on static stiffness. For higher magnitude, cyclic

loads, dynamic stiffness is used. Ropes under severe environmental loading will experience dynamic

loads (at low and wave frequencies) oscillating a mean load level. In the 3-slope model low and wave

frequency loads are treated separately. An alternative approach is to use upper and lower stiffness

bounds, although this may over-simplify the complex behaviour of synthetic ropes and is therefore

no longer recommended.

3.2.4 Axial damping

The hysteresis response of viscoelastic materials arises from the phase delay between changes to

the applied load and subsequent extension or recovery. The energy expended during each dynamic

load cycle can be estimated based on the area contained within load-extension response loops and

is related to the damped response of the rope. In addition to other damping mechanisms (such as

drag and viscous damping due to mooring line motions), axial damping will contribute to the overall

damped response of the moored device (Ghoreishi, S.R., Cartraud, P., Davies, P. and Messager, T.,

2007).

3.2.5 Considerations for the design of MRE mooring systems

The approaches to mooring system design and analysis introduced in preceding sections have been

developed for large offshore oil and gas equipment. MRE devices are typically smaller (in both size

and mass) and are therefore more dynamically responsive particularly in the case of WECs tuned to

maximise energy absorption. Therefore the loading scenarios which components are subjected to


27


are potentially very different. One particular scenario, which must be considered for devices located

in shallow water, is storm wave loading (i.e. 100 year return period). Numerical modelling has shown

that the 100 year wave is just preceded with a few seconds of zero mooring tension (corresponding

to slack mooring lines) and then the loading increases to the maximum (maybe as high as 50/60%) as

shown in Figure 3-5 (TTI, 2009). As the rope has time to relax and also starts from zero, the stiffness

would be much lower than that predicted by the oil & gas techniques. One example (TTI, 2009)

using this method showed the 100 year dynamic stiffness for a polyester rope to be EA/MBL of 10,

whereas approaches used by the oil and gas industry would give a value approaching 30. The key

learning here is that the rope stiffness must be measured for the expected loading scenario for the

particular device, water depth and environment. This advice has not changed since the Engineers’

Design Guide to Deepwater Fibre Moorings JIP, but seems to be often missed.

Figure 3-5: 100 year storm wave loading on a renewable device

More detailed tools have been developed using viscoplastic and viscoelastic formulae, finite element

and continuum methods (e.g. (François, M., Davies, P., Grosjean, F., Legerstee, F., 2010) (Chailleux,

E., Davies, P, 2003) ). Fibre Rope Modeller (FRM) developed by Tension Technology International

(TTI) is a commercially available modelling program which is capable of predicting the performance

of any rope constructions in terms of extension, torque and twist, as well as the effects of cycling

and certain damage mechanisms. Creep and the viscoelastic properties can also be modelled and

the properties have to be measured for the base fibre and input. FRM then models the rope

construction behaviour for any loading conditions. To date it has primarily been used to model ropes


28


used in deep water mooring applications (e.g. (Flory JF, Leech CM, Banfield SJ and Petruska DJ,

2005), but has recently been used in MRE applications. Although it is possible to include non-linear

load-extension properties of components (such as ropes) in most commercial mooring system design

software (Banfield, SJ, Casey, NF and Nataraja, 2005), this will not include viscoelastic, viscoplastic

and time-dependent behaviour. Simulation tools capable of modelling the (coupled) dynamic

response of the device – mooring systems which are also capable of accounting for the complex

behaviour of individual mooring components are not available at the time of writing. In Table 3-3,

offshore certification guidance and recommended practices for synthetic fibre ropes are listed.

Guideline Publication Date

Det Norske Veritas

Offshore Standard - Offshore Fibre Ropes: DNV-OS-E303 2013

Recommended Practice - Damage Assessment of Fibre Ropes for Offshore Mooring.

DNV-RP-E304

2005

Bureau Veritas

Certification of fibre ropes for deepwater offshore services. 2nd edition. NI 432 DTO

R01E

2007

International Standards Organisation

Fibre ropes for offshore stationkeeping: Polyester: ISO18692:2007 2007

Fibre ropes for offshore stationkeeping: High modulus polyethylene (HMPE):

ISO/TS14909:2012

2012

American Petroleum Institute

Recommended Practice for Design, Manufacture, Installation, and Maintenance of

Synthetic Fiber Ropes for Offshore Mooring: API RP 2SM (amended version)

2007

American Bureau of Shipping

Guidance Notes on the Application of Fiber Rope for Offshore Mooring 2011

Guidelines for the purchasing and testing of SPM hawsers 2000

Table 3-3: Offshore certification guidance and recommended practices for synthetic fibre ropes


29


3.3 Degradation

Potential degradation mechanisms include:

Tension fatigue

Creep

Compression fatigue

Hysteresis heating

Snatch loading

Damage during handling or installation

Tension fatigue is the wear caused by friction occurring between adjacent fibres which are subjected

to repeat cycling. Because this can be accelerated by the ingress of foreign particulates into the rope

structure, filtration screens are often used around the load bearing portions of the rope. After years

of deployment experience, the offshore industry has come to a consensus that polyester ropes have

superior fatigue characteristics when compared to other commonly adopted steel components such

as chain, shackles, H-links and spiral-strand work wire. Polyester has at least a factor 50 times longer

fatigue life than steel wire rope (Banfield, SJ, Casey, NF and Nataraja, 2005) and hence fatigue life

will never be an issue for polyester fibre moorings due to the excessively long fatigue life. As a result

of recent research (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010) nylon fatigue life has been

increased to such an extent that it can be used for permanent mooring systems.

The major issue of HMPE is its tendency to creep, which should be addressed in the design of

permanent moorings. One of the main concerns with HMPE's high creep rate is the potential for

failure via creep rupture (da Costas Mattos, HS and Chimisso, FEG, 2011). Although predictable, long-

term creep may necessitate re-tensioning of the lines, to avoid a drop in quasi-static stiffness of the

mooring system particularly during prolonged storm conditions. Factors affecting HMPE creep

behaviour are fibre type, applied load, load duration, and temperature. Recent development in new

grades of HMPE have led to vastly improved creep properties in both reduced strain and increased

rupture life, so it is vital to specify the applicable fibre grade to the application and to seek specialist

advice.

Stiffer materials such as aramid and to a much lesser extent HMPE are also susceptible to

compression fatigue, where fibres buckle under low loads and become concentrations for fatigue

damage under cyclic loading. Under dynamic loading it is possible for significant temperature

increases to occur from hysteresis heating. In extreme cases of localised heating this can result in

melting or peeling of fibres (Flory JF, Leech CM, Banfield SJ and Petruska DJ, 2005). Whilst this

phenomenon may only be limited to large diameter polyester ropes used on offshore platforms


30


(Overington, MS and Leech, CM, 1997), hysteresis heating may be an issue for smaller, more

dynamically responsive equipment such as WECs. Snatch loading, particularly when part of the

mooring system is temporarily slack may also result in hysteresis heating as well as permanent

extension.

Abrasion or cutting damage incurred during handling or installation will also reduce the performance

of the rope. Protective coatings such as woven jackets or polyurethane coatings will reduce the

likelihood of damage to load bearing components. However, it is important that safe working

practices are adopted during use and guidance documents such as those listed in the Appendix

should be followed as well as reports detailing lessons learned from offshore deployments (e.g.

(Noble-Denton, 2006)).

3.4 Cost and reliability assessment

Synthetic ropes have a lower cost per unit length than steel chains or wires. For example 24mm

diameter braid-on-braid polyester rope4 (MBL: 137kN) is 715 €/100m which is considerably less than

1679 €/110m for 16mm studlink chain5 (MBL: 150kN). As introduced in Section 1, the ability to

reduce peak loadings means that lower capacity connecting components can be specified and the

load bearing requirements of the moored structure are reduced; hence indirect cost savings can also

be achieved. To assess potential cost savings, Ridge et al. in (Ridge, I.M.L., Banfield, S.J. and Mackay,

J., 2010) carried out comparative cost analysis of several single-line taut-moored and catenary

configurations, including several anchor types. The advantages in using durable yet lightweight

components instead of conventional mooring chains was highlighted, such as the use of nylon ropes

to allow lower gauge mooring chain to be used for anchor-chain-surface buoy-rope-device

configurations. This configuration could potentially save over £90K per mooring line (Table 3-3).

Clearly these costs are partially attributable to the specification of lower capacity components such

as anchors and savings of this magnitude may not be achievable for all applications. However there

is clearly scope for further cost reductions by bulk ordering of components for 10s or 100s of devices

in an array deployment.

4 Price obtained on 13/06/2014 from Lankhorst Ropes and does not include the cost of splicing.

5 Price obtained on 18/06/2014 from Saxton Marine and is based on 4x27.5m lengths fitted with Kenter shackles.


31


Elements Mooring line Anchor Total cost

(£) Nominal

size (mm)

Length Unit weight

(kg/m)

Total weight

(tonnes)

Cost (£) Cost (£)

Chain 81 5d 152 38 74,733 66,784 141,516

Chain

Polyester

Buoy

73

104

14.1t

5d

d

123

8.25

30.75

0.41

58,213

3,300

6,800

29,486 97,799

Chain

Nylon

Buoy

54

80

9.8t

5d

d

66

4

16.5

0.2

31,466

1,722

4,900

13,027 51,115

Table 3-4: Cost comparison carried out by Ridge et al. (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010) of three

hypothetical catenary mooring systems located in d = 50 m water depth. Buoyancy of the buoys is specified in

tonnes and drag embedment anchors are specified.

The capital cost of components is clearly only part of the total lifecycle costs associated with

mooring components. For the configurations listed in Table 3-3, the lightweight configurations

would be easier to handle and transport during installation, maintenance and recovery operations

and may even allow for smaller, less expensive work boats and associated equipment to be used.

Whilst Ridge et al. provided mooring line weights for the configurations assessed, anchor weights

are not specified in (Ridge, I.M.L., Banfield, S.J. and Mackay, J., 2010) and both would need to be

considered when determining suitable vessels and procedures for installation and recovery

operations.

Reliability assessments are carried out to ensure that all mooring components have the capacity to

withstand 1) peak loadings, 2) fatigue cycling as well as 3) handling and environmental exposure.

Reliability predictions can be made from existing, published data although the accuracy of these is

likely to depend on how similar the application is and this uncertainty will be explored in

forthcoming WP4 tasks.


32


Predictions of accumulated fatigue life are based on the number of load cycles6 for a given time

interval (and also load range). These two parameters are established using cycle counting methods

(e.g. rainflow analysis) based on either field measurements (e.g. (Weller SD, Davies P, Vickers AW,

and Johanning, L, 2014)) or dynamic simulations. Damage accumulation methods (such as the

Pålmgren-Miner rule (Thies, PR, Johanning, L, Harnois, V, Smith, HCM and Parish, DN, 2014) or

spectral methods (DNV, Offshore Standard – Position Mooring. DNV-OS-E301, 2010)) can then be

used to determine the proportion of remaining life left in components based on fatigue life curves,

such as those presented in Section 2.2. This technique is well-established for steel components and

has recently been applied to MRE mooring components (Thies, PR, Johanning, L, Harnois, V, Smith,

HCM and Parish, DN, 2014). The use of damage accumulation methods for synthetic ropes is well

proven for polyester mooring ropes and it has been established that Miner’s summation is an

applicable technique. The applicability of Miner’s summation to nylon ropes is subject to ongoing

studies. It should be noted that the lower bound calculated tension-tension fatigue with synthetic

fibre ropes for offshore moorings runs to many hundreds of thousands of years, so that fatigue

degradation will never be an issue. Unlike chain and wire rope the calculated lower bound fatigue

life is often in the hundreds of years so when the safety factor of 10 is applied the design life is often

too close for comfort to the 30/40 year required life. Thus, it is no surprise that fatigue failures

occur, typically due to out of plane bending of the chain in the fairlead. Failure due to fatigue is

unsurprisingly a hot topic as there is simply not enough margin in the fatigue life. In addition to

establishing the number of cycles, counting methods applied to simulated tension time-series enable

the identification of peak loads to ensure that factors of safety are correctly specified.

Whilst the numerical methods to predict rope performance introduced in Section 2.5 have a role to

play in reliability prediction, methods used to establish reliability are shaped by physical testing and

offshore experience. The assessment of synthetic rope reliability is not just seen as a preliminary

design stage but as an on-going process as part of a wider lifecycle strategy. Specifically, procedures

for the assessment of damage through in-situ inspection are well-established (DNV, 2005) and

should be considered.

3.4.1 Reliability experiences from the oil and gas industry

3.4.1.1 Steel wire and chain

A comprehensive study was conducted (A Historical Review on Integrity Issues of Permanent

Mooring Systems, 2013) on the mooring line failures in permanent designed oil & gas production

6 For steel components, stress, instead of load cycles are quantified


33


platforms. During the period 2001-2011 9 system failures occurred in around 300 moorings which

give a probability of failure Pf 3.0 x 10-3.

However, system failures are defined as any incident involving breakage of 2 or more lines or riser

damage. With this definition, an incident would not be counted as a failure if there is only a single-

line break. Production systems are always designed with redundancy in the event of 1 line failing.

Loss of station keeping or damage to risers should not occur.

Given that many renewable devices designed and installed so far using a 3 or 4 point mooring

system, there is no redundancy. Maybe a different definition of failure is required for renewables

which is dependent on the array spacing. It may be more prudent to define failure as any mooring

line or component. Since in an array, loss of any line could lead to many devices being damaged in a

progressive collapse scenario. The actual total number of mooring line and component failures was

40, which gives a Pf of 13.0 x 10-3.

Some key learning were established in points (A Historical Review on Integrity Issues of Permanent

Mooring Systems, 2013) and are summarised below:

Some of the failures could have been prevented through more robust inspection and

monitoring

Some were due to new phenomena, e.g. out of plane bending in chain

In the majority of instances, failures occur at an interface or discontinuity

Chain and wire rope in contact with seabed was a common issue

Corrosion had been a major contributor to several incidents

It is more cost effective to build redundancy or margin in a new design during CAPEX phase

compared to a mooring repair or replacement in the future

Inspection of wire or chain seems not to have identified incipient failure modes

Given the long standing research, extensive design and engineering, the failure rate is still much

higher than the industry expects. Even for these steel components and mooring lines, manufacturing

inspection and in service NDT has not reliable or able to identify many of the failures.

Thus, it is clear that the renewable industry needs to take a new approach to make moorings more

reliable as the number of devices and mooring lines over the next 10 year period could easily be 100

times greater than the oil and gas market. The choices are to increase reliability of steel moorings

or not use them, or switch to fibre moored only with no steel components. There is another choice

to design fibre or steel moorings with redundancy, but this will drive up costs and is not desirable in

terms the industry aims to reduce cost per unit energy. This latter option is being studied under the


34


MRCF (Carbon-Trust, 2014) grant and a mooring system with no steel components will be deployed

in summer 2015.

3.4.1.2 Fibre rope

From the same study (A Historical Review on Integrity Issues of Permanent Mooring Systems, 2013)

the only statistics gathered so far was for a permanent design polyester moored export buoy in

1300m water depth of West Coast Africa where one polyester line failed due to cutting (P. Jean, K.

Goessens, D. L’Hostis, 2005) (TTI, 2002) from a wire rope. The polyester line only broke due to the

two adjacent chains in that sector failing, transferring their load to the polyester. The parallel sub

rope rope had around 2/3 of the subropes cut, but the remaining subropes still held the pretension

until the adjacent chains failed. So it could be argued there is redundancy in this design of rope. The

cut damaged polyester rope was extensively examined and found to be in perfect condition (Ref 4)

and had 95% residual strength with no other damage found. Subrope stiffness properties were

extensively laboratory tested (Ref 5) and numerically modelled with Fibre rope Modeller and found

to be unaffected even though the remaining part of the rope had been loaded to near breaking load.

During the same period 2001-2011 there were around 47 permanent designed productions

platforms moored with polyester, which gives a Pf of 2.1 x 10-3. Using the same definition of failure

of any line or components gives a failure rate 6.2 times higher for steel moored systems compared

to fibre rope. There are a few hundred polyester moored MODU systems for which no statistics are

available. This data should be gathered as it would provide additional information, albeit temporary

designed systems.


35


4 CORROSION

4.1 Background

Both floating and submerged ocean energy devices are exposed to the harsh marine environment,

including highly corrosive salt water, in particular in the aerated splash zone, microbiological fouling

and marine growth. Corrosion is of particular concern for MRE devices, because it is a contributing

factor to performance degradation: corrosion fatigue is known to significantly lower the fatigue

strength of the affected material. Studies (Little et al. (2008); Videla and Herrera (2005)) also suggest

that both fouling and marine growth both initiate and accelerate the material degradation through

assisting the corrosion process and by causing increased hydrodynamic loads. Whilst these aspects

are known material phenomena, they have not been investigated in sufficient detail for ocean

energy applications, with a view on how to quantify, mitigate and monitor corrosion, fouling and

marine growth. There is a wide variety of corrosion measurement techniques including non-

destructive testing methods, analytical chemistry, operational data fluid electrochemistry and direct

corrosion monitoring. An ideal combination of these methods has not been established for MRE, yet.

Thus an objective of this section is to review the different methods with regards to their suitability to

derive a ‘best practice’ for corrosion mitigation and monitoring in an efficient and cost-effective

manner.

Herein, the main aspects concerning corrosion and protection measures are summarized for MRE

devices with respect to technical performance and costs. Since only a few devices have been

installed so far, and most of them have been in operation for less than 10 years, there is little

information about corrosion. Hence, the technical evaluation is therefore mainly based on

information from other industries, primarily offshore oil and gas production and offshore wind

technology.

Corrosion is the degradation of a material due to a chemical reaction with the surrounding

environment, generally due to a combination of oxygen and moisture. Corrosion is amplified in the

marine conditions due to the presence of salt in seawater. As MRE devices work in highly corrosive

marine environmental conditions, the material should be appropriately protected or the impact of

corrosion should be negated by other means. It is necessary to identify which zone each component

of the device will exist within to be able to best consider forms of corrosion protection during

design. The rate of corrosion will vary due to the differing oxygen/moisture content in the various

zones, for marine applications. The corrosion zones may be classified as follows (EMEC, 2009):

atmospheric

splash


36


inter-tidal

submerged

buried

Corrosion is caused by a chemical (or electrochemical) reaction between a metal and its

environment that produces a deterioration of the material and sometime its properties. For

corrosion to occur, the following basic conditions must be fulfilled:

metal surface is exposed to the environment (bare steel in physical contact with the

environment)

the presence of an electrolyte (e.g. water containing ions, the electrolyte must be able to

conduct current)

the presence of an oxidant (a chemical component causing corrosion (e.g. oxygen, carbon

dioxide)

If one of these conditions is not present, corrosion will not occur. Table 4-1 summarises prospective

corrosion mechanisms for subsea oil and gas production equipment. The presence of organic acids

and sulphur containing compounds (e.g. elemental sulphur) may aggravate the corrosion in the

system.

Table 4-1: Internal and external corrosion mechanisms in a subsea oil and gas production environment (DNV,

MATERIAL RISK - AGEING OFFSHORE, 2006).


37


Figure 4-1: Corrosion process, https://www.boundless.com/readings/3151/

4.2 Degradation Mechanisms

4.2.1 Hydrogen Induced Stress Cracking

Cathodic protection may be detrimental for some materials due to Hydrogen Induced Stress

Cracking (HISC). Hydrogen Induced Stress Cracking (HISC) is caused by a combination of load/stress

and hydrogen embrittlement (HE) caused by the ingress of atomic hydrogen into the metal matrix

formed at the steel surface due to cathodic protection (CP). High strength steel (SMYS > 500 MPa)

and some corrosion resistance materials (13Cr-steel and duplex stainless steels) are susceptible to

HISC. Solution annealed austenitic stainless steels and nickel based alloys are generally considered

immune to HISC. DNV RP B401 Sec. 5.5 gives recommendations with regards to materials maximum

hardness level and the specified minimum yield strength for safe combinations of CP. Bolts in

martensitic steels heat treated to SMYS up to 720 MPa and maximum hardness level of 350HV

(ASTM A182 grade B7 and ASTM A320 grade L7) have documented compatibility with CP (see also

Norsok M-001 Sec. 5.6). Factors influencing HISC of duplex stainless steel have been recapitulated in

DNV RP F-112 with recommendation for design criteria based on best practice and on state-of-the-

art knowledge (i.e. strain/stress criteria). HISC is abrupt of nature and it is expected to occur during

the first years of the installations design life if the conditions are ideal (DNV, MATERIAL RISK -

AGEING OFFSHORE, 2006).

https://www.boundless.com/readings/3151/

https://www.google.no/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&docid=7fKJtQ1cRv8u5M&tbnid=nw1CYwbPmaFDAM:&ved=0CAUQjRw&url=https://www.boundless.com/readings/3151/&ei=hqF0U62CF8GTywP6rYCwCw&bvm=bv.66699033,d.bGQ&psig=AFQjCNHQark3kbgFhPVvmhfs1MY6kzHoYQ&ust=1400238841308381


38


4.2.2 CO2-corrosion

CO2-corrosion or sweet corrosion is not anticipated for corrosion resistant materials (e.g. 13Cr, 316L,

22Cr, 25Cr, Alloy 625). Carbon steel, however, will be subjected to CO2-corrosion. The corrosion rate

is dependent on the partial pressure of CO2, the temperature, the flow regime and the in-situ water

pH level. The corrosion takes the form of localised- (‘pitting’), uniform- and grooving- (e.g.

longitudinal, transverse) attacks and is a time dependent degradation mechanism. CO2-corrosion can

be mitigated by the use of corrosion inhibitors and/or by pH- stabilisation of the process fluid

(primarily applicable for pipelines).

4.2.3 O2-corrosion

Internal corrosion due to the presence of O2 is in principle not expected in oil and gas production

systems since no oxygen shall be present in the process medium. Ingress of oxygen may increase

corrosion in the system. Water used for water injection can be either deaerated or aerated, which

will have an impact on the rate of corrosion. Due to the removal of oxygen in deaerated water, the

corrosion rate of carbon steel will be low, whereas in systems carrying aerated water a higher

corrosion rate must be anticipated. This can be relevant for MRE devices; as an example the

pressurised piped water systems (Oyster, Seatricity, etc). Oxygen corrosion is a time dependent

corrosion mechanism and takes principally the form of uniform corrosion, but localised attacks may

also occur (‘pitting’). Corrosion resistance alloys (CRA’s) and titanium can be used for seawater

service but there are certain design limitations regarding the use of such materials (e.g.

temperature, presence of crevices, chlorination etc.). Corrosion of CRA takes the form of localised

attack. The unfortunate combination of material and operating environment will, for most cases

result in a corrosion failure during the initial phase of an installation’s life. Environmental cracking

due to H2S corrosion due to the presence of H2S is primarily related to environmental cracking (i.e.

sulphide stress cracking (SSC)). Both carbon steel and CRA’s are susceptible to SSC. The risk for SSC is

dependent on the partial pressure of the H2S, the in-situ pH-value, total tensile stress, chloride ion

concentration, presence of other oxidant etc. (for details reference is made to ISO-15156). Below a

critical partial pressure of H2S no SSC is expected to occur. However, for partial pressures above this

limit there is an increasing risk for SSC and the environmental condition is termed as sour. The

resulting failure mode is cracking and it is of abrupt nature. SSC is controlled by specification of the

material properties (e.g. hardness) and the manufacturing process. For susceptible materials,

environmental cracking is expected to occur during the initial phase of production and is not

expected to have a time dependent development similar to ‘sweet’ corrosion. The risk for

environmental cracking should for such cases be subjected to evaluations with respect to the

material properties and the new service condition.


39


4.2.4 Microbiologically Induced Corrosion (MIC) Corrosion fatigue

The two best known bacteria of concern for the oil and gas industry are the sulphate reducing

bacteria (SRB) and the acid producing bacteria (APB). They may live synergistically in colonies

attached to the steel surface, where the SRB bacteria live beneath the APB colony. SRB bacteria live

in oxygen-free environments and use sulphate ions in the water as a source of oxygen. H2S is

produced as a waste product from the SRB, producing a corrosive environment locally in connection

with the colony of bacteria. The risk for obtaining MIC will depend on the availability of nutrients,

temperature, water and flow condition. MIC takes the form of localised attack causing a pinhole

leakage of a pipe. High corrosion rate can be anticipated (>1 mm/year) if the conditions are ideal.

MIC has been obtained in oil production systems as well as on steel exposed (e.g. anchor chains) to

seabed sediments. The location of MIC is difficult to predict. For pipeline systems, treatments with

biocide may be effective as a preventive measure. A common source for bacteria in a closed system

is seawater. Use of untreated seawater for hydro testing should therefore be avoided (DNV,

MATERIAL RISK - AGEING OFFSHORE, 2006).

4.2.5 Corrosion fatigue

On a general level fatigue is affected by environmental conditions and in particular by corrosion.

HISC and sour service conditions may facilitate fatigue crack initiation. Metal loss by corrosion will

generally enhance crack growth, but under reversed loading conditions (tension-compression)

corrosion products may reduce the “impact” of the total stress range due to “crack closure”.

Corrosion fatigue occurs in metals as a result of the combined action of cyclic stress and a corrosive

environment. For a given material, the fatigue strength (or fatigue life at a given maximum stress

value) generally decreases in the presence of an aggressive environment. When corrosion and

fatigue occur simultaneously, the chemical attack accelerates the rate at which fatigue cracks

propagate. Materials which show a definite fatigue limit when tested in air at room temperature

show no indication of a fatigue limit when the test is carried out in a corrosive environment.

Corrosion fatigue crack growth might be influenced by many variables, also by environmental

variables (gaseous or liquid environment, partial pressure of damaging species in gaseous

environments, temperature, pH). A number of methods are available for minimizing corrosion

fatigue damage (DNV, MATERIAL RISK - AGEING OFFSHORE, 2006):

The choice of material for this type of service should be based on its corrosion resistant

properties rather than the conventional fatigue properties (e.g. stainless steel over heat-

treated steel)


40


Protection of the metal from contact with the corrosive environment by metallic or non-

metallic coatings (provided that the coating does not become ruptured from the cyclic

strain)

Addition of a corrosion inhibitor in closed systems to reduce the corrosive attack

Elimination of stress concentrators by careful design

Figure 4-2: Corrosion effects on fatigue life,

http://www.corrosionclinic.com/types_of_corrosion/Corrosion%20Fatigue.htm

Galvanic corrosion may occur when there is an electrical coupling between dissimilar metals. The

least noble material (anode) will be sacrificed on behalf of the noblest material (cathode). The extent

of accelerated corrosion resulting from galvanic coupling is affected by the electrochemical potential

difference between metallic couple, the nature of the environment (rate of corrosion) and the area

ratio of anodic- and cathodic areas (small anode to cathode area ration is unfavourable). Galvanic

corrosion is a time dependent form of corrosion and result in a uniform corrosion attack. The

possibility for obtaining galvanic corrosion should be evaluated during the design phase. For cases

where a galvanic couple is inevitable, a distance spools of a non-conducting material can be installed

or installation of a galvanic spool with sufficient wall thickness where the material is intended to

corrode (i.e. sacrificial spool) (DNV, MATERIAL RISK - AGEING OFFSHORE, 2006).

4.3 Cost and reliability implications

One of the critical challenges for marine energy production is to reduce costs (Knudsen, 2010). Both

capital costs (CAPEX) and operational costs (OPEX) must be considered. Offshore maintenance

operations are generally challenging and expensive, so that maintenance free solutions may be used,

http://www.corrosionclinic.com/types_of_corrosion/Corrosion%20Fatigue.htm

http://www.google.no/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&docid=81z5CNSo_O4jEM&tbnid=H3akG80feAUPdM:&ved=0CAUQjRw&url=http://www.corrosionclinic.com/types_of_corrosion/Corrosion Fatigue.htm&ei=OqR0U_qxDMTgygO-jICQBg&bvm=bv.66699033,d.bGQ&psig=AFQjCNFNUNqQmK4OatS5BWmJsRFio69AIw&ust=1400239503578907


41


if possible. In particular, offshore coating maintenance is generally very expensive. For oil and gas

installations, where you have reasonable access to the surfaces to be coated, the cost is estimated

to about 120 €/m². However, for an offshore wind turbine tower, access difficulties to the tower are

likely to dramatically increase the costs beyond the oil and gas level. In order to get a person to the

area for maintenance, a special vessel should probably be used. The cost of such vessels may reach

100000 €/day. For a large wind farm, where a custom-made vessel may be permanently located at

the field for maintenance operations, the daily costs will probably be significantly lower. However,

maintenance costs will still be high. Using long life maintenance free coatings may be beneficial in a

life cycle cost perspective.

Table 4-2: Costs for coatings and anodes in the submerged zone, all costs in k€ (Knudsen, 2010).

4.4 Concrete

The design of concrete members should ensure that pre-tensioned tendons and rebars

(reinforcement bars) are sufficiently protected against the corrosive environmental conditions.

Corrosion protection of pre-stressing tendons and reinforcement bars (rebars) is an important

aspect in the design of concrete structures.

The casting of concrete elements is important and shall also be in accordance with design

specification documents. Normally, corrosion protection is provided using detailed specification of a

durable mix design through consideration of chemical exposure such as chlorides and sulphates and

also freeze-thaw damage.

Inspection procedures are implemented during the casting of the elements to ensure workmanship

is undertaken to adopted QA systems. Specially, the specification of a sufficient cover thickness (i.e.

the thickness of concrete between the free surface of the member and rebar) and the limitation of

the allowable size of cracking to minimize the amount of moisture that attacks the tendons and

rebars should be checked (EMEC, 2009).


42


Figure 4-3: Illustration of concrete corrosion in offshore environment,

http://www.corrosion-club.com/concreteintro4.htm

4.4.1 Metals

For steel structures, the corrosion protection should consider the following points:

a corrosion allowance (CA) is incorporated in the design (e.g. DNV-OS-E301 Position

Mooring)

an inspection regime to be employed

stress in the component (both mean stress and fatigue) and calculated factor of safety (FOS)

location of the component relative to the seawater surface

areas subject to wear

for areas not protected against corrosion (or that have been painted only with ordinary

coatings), an additional corrosion allowance shall be considered; BS 6349 also provides

advice on free corrosion for steel in maritime structures.

It is important to consider corrosion rates in the design. This should be determined using previous

similar service experience and a code of practice which defines corrosion rates. Special consideration

is needed for aggressive local corrosion (pitting and grooving) and an inspection regime should be

used to establish the accuracy of corrosion rates assumed in the design.

http://www.corrosion-club.com/concreteintro4.htm

http://www.google.no/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&docid=Wc85M70r7mcysM&tbnid=Qm7JDIOp3p3XVM:&ved=0CAUQjRw&url=http://www.corrosion-club.com/concreteintro4.htm&ei=FqN0U6XsLND-yAPe94HYAQ&bvm=bv.66699033,d.bGQ&psig=AFQjCNHcryEo__AB9d_wRE-PafNr3VKL5Q&ust=1400239134358934


43


External corrosion is for most submerged equipment controlled by the use of an external corrosion

coating and a cathodic protection (CP) system. The design of the CP system is dependent on the

design life of the equipment and the type and quality of the external coating system in question. For

carbon steel components a corrosion allowance must then be added. The CA that must be added will

depend on the availability of oxygen (oxidant). For areas with limited access of oxygen, such as

within hollow profiles of structural steel, the corrosion rate will be low and a moderate CA is

tolerable, whereas for instance chains that are freely exposed to seawater, a higher corrosion rate

must be accounted for. The CA is normally determined as a part of the design and is based on the

specified design life of the component. Certain corrosion resistant alloys (CRA’s) and titanium are

resistant to seawater corrosion under North Sea ambient seawater conditions and can be used

without cathodic protection (DNV, MATERIAL RISK - AGEING OFFSHORE, 2006). Cathodic protection

is polarizing the steelwork to a sufficient level in order to minimize corrosion and is particularly

effective for the submerged zone. It should be designed for a period equal with the design life of the

structure or the dry docking interval. Cathodic protection can be achieved applying impressed

current anodes or sacrificial anodes (or a combination of both).

Figure 4-4: Cathodic protection, Courtesy of Deepwater Corrosion Services Inc.

http://www.cathodicprotection101.com/

If protection is primarily by an integrated current system (e.g. Figure 4-4), sufficient sacrificial anodes

should be considered to polarize the critical regions of the structure from transportation/installation

until full commissioning of the integrated current system.

http://www.cathodicprotection101.com/

http://www.google.no/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&docid=Ci016pj07fRLxM&tbnid=iMlf8Lc4SZkomM:&ved=0CAUQjRw&url=http://www.cathodicprotection101.com/&ei=0L5YU4KiGumAywPyooKQAw&bvm=bv.65397613,d.bGQ&psig=AFQjCNHPFy5Mdc_ohwuOLH1l_l9UwKNTUQ&ust=1398411081723207

http://www.google.no/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&docid=Ci016pj07fRLxM&tbnid=iMlf8Lc4SZkomM:&ved=0CAUQjRw&url=http://www.cathodicprotection101.com/&ei=3b5YU-K-AomeyQOZ1IHADA&bvm=bv.65397613,d.bGQ&psig=AFQjCNHPFy5Mdc_ohwuOLH1l_l9UwKNTUQ&ust=1398411081723207


44


4.4.2 Protective Coatings

Protective coatings been widely applied in a wide range of offshore applications. The surfaces of the

components and the substructure are divided into four different zones that differ with respect to

corrosivity and corrosion protection methods (Knudsen, 2010).

1) Coatings for atmospheric zone:

A coating system consisting of thermally sprayed zinc and a protective organic paint system on top is

frequently used today and will likely give the desired lifetime. Cost savings can be achieved by:

Decrease film thickness of the zinc coating

Decrease corrosion rate of the zinc coating by changing the alloy composition

Decrease the number of paint coats, but still have UV resistance and sufficient barrier

against ion transfer

2) Coatings for splash zone:

Cost savings can be achieved by:

Decrease corrosion rate of the zinc coating by changing the alloy composition

Decrease the number of paint coats, but still have UV resistance and sufficient barrier

against ion transfer

3) Coatings for submerged zone:

Cost estimates show that a CP system without coating has a lower cost than the coating/CP

combination. Hence, improved coatings for submerged service should not be our focus, unless the

coating costs can be reduced to a fraction of today’s level.

4) Coatings for internal surfaces:

Sufficient corrosion protection probably can be achieved with rather simple coating systems, so the

potential for savings is smaller. The use of dehumidification instead of protective paint is a viable

alternative, but coating is probably a more robust method for the projected 20 year lifetime of MRE

devices. Potential tasks for further research may be investigation of simple, low cost coatings.

Protective coatings which have good abrasion and ultraviolet (UV) resistance attributes are applied

for areas that are not continuously submerged (such as the splash zone). Protective coatings include


45


the use of galvanizing or epoxy based paint systems. Such coating systems generally have design

lives in the order of 5 to 10 years and should be reapplied.

Thicker steel sections based on corrosion rates and the design life of the structure can mitigate the

effects of corrosion. This approach provides a sacrificial thickness of steel which ensure that the

remaining cross section of the section provides sufficient structural integrity. The inspection regime

should confirm the corrosion rates assumed in the design. Consideration is needed for aggressive

local corrosion (pitting and grooving). The chain size chosen should account for the corrosion/wear

which can occur over the service life of the anchor chain and associated components. Additional

greater margins are required where chains are subjected to high wear rates.

The surface of the steel wire used in mooring lines is (almost) always protected by galvanising. The

thickness of the zinc coating (usually expressed as the weight in g/m2) depends on the class of

galvanising, which may be “normal” or “heavy marine”: Class B or A respectively (BS EN 10244-2,

2001). It is also common practice for the wire manufacturer to provide an average cover significantly

in excess of the minimum required by standards, to allow for variation in the coating process. Class B

galvanizing involves drawing after the hot-dip galvanizing, which gives better control of wire

diameter and coating thickness; to achieve the greater thickness required for class A, the hot-dip is

the final process which makes diameter more difficult to control and limits tensile strength.

Figure 4-5: Left: corrosion and break-up of IWRC of 76 mm ungalvanized MODU mooring rope after five years'

service; right: IWRC of 90 mm galvanised MODU mooring rope after 7 years (C.R.Chaplin, A.E. Potts and A.

Curtis, 2008)

Table 3 lists some coating systems applied inside and in the external atmospheric zone on towers for

six offshore wind farms. On the external surface metallization was used on five out of six wind farms.

Though the metallization alloys are not specified it is fair to assume that the 85% zinc 15%

aluminium alloy has been used. On the Utgrunden wind farm, a zinc rich epoxy was used instead of

metallization. On all six wind farms two layers of epoxy, approximately 100 μm thick each, and 50

μm polyurethane topcoat was applied. On the internal surfaces there is a larger variation regarding


46


coatings between the wind farms. This may be related to use of dehumidification on some

installations, which will enable use of simpler coating systems.

Hywind and Sheringham Shoal were developed by Statoil. Table 4 shows coating selection for the

various external zones. The coating selection for the atmospheric zone differs from what Statoil

normally use for oil and gas installations, while the thick two-coat polyester in the splash zone is

frequently used in oil and gas as well. The 2 x 250 μm epoxy in the submerged zone is also used in oil

and gas applications.

Table 5 shows coatings applied on five different jacket projects at Aker Verdal the last seven years.

Only the Buzzard jackets are for wind farms. The other four jackets are for oil and gas installations.

The atmospheric zone on a jacket is difficult to access for coating maintenance. Hence, long lifetime

maintenance free coating systems are normally preferred. That is reflected in the use of thermally

sprayed aluminium (TSA) on four of the jackets. For the Ekofisk jacket a thick two-coat polyester was

used, which also is a long life coating. TSA with a full paint system on top, which was used on

Goldeneye and Claire, is not used anymore since this combination has been shown to give severe

corrosion problems.


47


Table 4-3: Coating specification outside and inside for steel towers for wind turbines in different wind parks

given by Hempel (Knudsen, 2010)


48


Table 4-4: Corrosion protection for Hywind offshore wind turbine and the Sharingham Shoal offshore wind park

Table 4-5: Corrosion protection systems for the five last steel jackets produced by Aker Solutions, Verdal


49


5 NOVEL COMPONENTS

In this section several recent innovations are introduced which have the potential to contribute to

the development of economic and reliable mooring and foundation systems.

5.1 Marine micropile foundations

Micropile anchors (see Figure 5-1) are a new technology that can be utilized for offshore renewables

to decrease the final cost of produced energy (Dallas J. Meggitt, Jon Machin, Eric Jackson and Robert

Taylor, 2013). Micropile anchors can be used for as an alternative for conventional anchors as well as

for applications that require fixing objects to the seafloor. Marine micropile anchor systems typically

comprise multiple, relatively small, hollow micropiles (3-6 cm diameter) that are drilled into the

seafloor using an expendable drill bit. Grout is pumped through the hollow micropile, filling the hole

around the pile. The micropiles are grouted in place, through a template that then forms the anchor

assembly.

However, conventional anchors and foundations normally include large diameter mono-piles, gravity

bases and steel spread foundations that are secured by large driven or drilled-in piles. For floating

structures, drag embedment anchors, piles, direct embedment anchors and clump (“deadweight”)

anchors are also utilized. One configuration, for example, is concrete deadweight anchor. This type

of anchor requires large, and usually specialized, vessels for transport and installation. Pipelines are

often “anchored” by being covered with rock riprap. Other ocean engineering applications often are

not anchored at all, or are held down on the seafloor with large weights, concrete mattresses and

the like.

Micropile anchor advantages:

Broad range of seafloor conditions and water depths

Based on existing terrestrial technology

Self-drilling, caseless installation

Services all load cases

Long service life

Micropile technology can dramatically reduce system and installation costs

o Less Material

o Smaller, less-costly installation vessels

Smaller, lighter than conventional anchors or foundations

Highly adaptable and scalable designs

Very high unit anchoring efficiency


50


Figure 5-1: Micropile, Courtesy of Marine Micropile Technology Group, http://www.marinemicropile.com

Comparison with gravity anchors

Gravity anchors and monopiles require special equipment and vessels

Gravity anchors depend on net weight to develop holding capacity

Gravity anchors are substantially heavier and larger than comparable capacity Micropile

anchors

Micropiles can be installed from smaller vessels and do not require very specialized handling

equipment/methods

5.2 The Exeter Tether

The mooring system of a marine renewable energy (MRE) device has two key requirements; to keep

the device on station whilst maintaining mooring tensions within acceptable limits. As introduced in

Section 3, the use of compliant mooring components such as synthetic ropes is one way to mitigate

both peak and fatigue loads. This has the added benefit of allowing a reduction in mass of both the

device structure and mooring system, hence reducing costs and improving system reliability. Certain

applications may however require mechanical properties that are not satisfied by commercially

available ropes, for example even greater compliance than is provided by nylon. The Exeter Tether is

a novel mooring tether design developed and patented by the University of Exeter (Parish-

http://www.marinemicropile.com/


51


Johanning, 2012). One of the unique features of the Tether is that the design can be tailored to

satisfy the application (i.e. the specification of axial stiffness and minimum break load). The first

stage of performance and reliability assessment of the tether is detailed by Gordelier et al. in

(Gordelier T, Parish D and Johanning L, 2014). The proof of concept stage included rigorous testing of

10 tether prototypes (manufactured by Lankhorst Ropes) at the University of Exeter’s Dynamic

Marine Component Test Facility (DMaC), including:

Performance tension-extension tests

Breaking load test

Dynamic tension tests at different load frequencies

Fatigue endurance test

In addition sea trails utilising the South West Moorings Test Facility (SWMTF) were successfully

carried out between June and November 2013 to determine functional performance and durability

of the Tether (Figure 5-2).

Figure 5-2: Deployment of the SWMTF with two Exeter Tethers (left, foreground)

5.3 Bag anchors

Research (Carbon-Trust, Mooring systems, anchors and intermediate components (MOSAIC), 2007)

was started in 2007 to develop a lower cost and carbon footprint anchor system. Many WEC

devices will need to be moored in shallow water where the seabed sand/mud layer may only be a

few metres deep. Such conditions are insufficient for drag anchors and alternatives are either very

expensive (e.g. rock anchors) or very large (e.g. concrete gravity anchors). These also require very

large and expensive day rate vessels for installation. The bag anchor system comprised flexible bags

filled with aggregate and contained with a fibre rope net. The design intent was no metallic


52


components anywhere in this system and this was achieved. The design allows for a smaller

installation vessel to be chartered as clusters of small bag anchors could be used to make a larger

anchor. The main advantages of bag anchors are:

Cheaper mooring manufacturing costs per system installation

Cheaper mooring installation/deployment costs per system installation using smaller vessels

Potentially cheaper recovery costs per system installation

Lower Carbon footprint of mooring anchors

Potentially lower carbon footprint of installation, deployment and recovery of the mooring

anchors

In 2010 (Carbon-Trust, Moorings and anchors for wave energy devices, 2010), a 28 tonne bag anchor

was built and deployed for field trial and verified that the anchor holding capacity met design criteria

for a wide range of vertical angles and slewing. The next stage (Carbon-Trust, Testing, qualification

and commercialisation of advanced mooring system for wave and tidal arrays, 2014) is to deploy bag

anchors on a mooring system in EMEC Orkney in 2014 to gather long term field experience.

Figure 5-3: Bag anchor

5.4 Connectors

Connectors are required to join mooring line segments of varying materials together (e.g. fibre ropes

to a wave or tidal device). Traditional jewellery for oil and gas markets has a high failure rate that

would make OPEX costs prohibitive for renewables applications. A research study (Carbon-Trust,

Mooring systems, anchors and intermediate components (MOSAIC), 2007) was conducted to

develop a generic suite of connectors using SDSS for the side plates as shown in Figures 5-4, 5-5 and

5-6. The generic design followed guidance from BS 5950 Part 1:2000 to provide a robust connector


53


design. Rolled plate, with machined profile was selected as it is a very reliable material since failures

are fairly common with cast or welded components. The spool for the fibre rope was made from

Orkot (a thermoset composite material) which does not corrode or cause abrasion to the fibre rope.

Since MRE devices are moored in shallow water, the 1st order motions are high and quite large

angles are induced between connector and rope. It is essential for the spool to rotate in the

connector, rather than the rope sliding or bending. Hence for the design to be maintenance-free it

included SDSS pins to allow the Orkot spools to rotate. Figure 5-7 shows an in-line connector for a

400 tonne polyester rope.

Figure 5-4: Triplate connector Figure 5-5: Inline or end connector

Figure 5-6: Generic range of mooring connectors Figure 5-7: SDSS Inline connectors with pins


54


6 CONCLUSIONS

It has been the purpose of this report to review existing component assessment functions for array

foundation, anchor, and mooring applications. In addition, the introduction of new components

made from well-established or novel materials/construction, and capabilities towards reliability and

cost prediction in terms of corrosion effects, grouts and synthetic materials have been considered.

Grouting systems are widely used in terrestrial and maritime civil engineering works and hence

material characteristics as well as degradation due to environmental exposure are well understood.

However, lessons can still be learnt from the offshore wind industry where overestimation of axial

capacity of grouted connections and deviations in grouting characteristics due to composition,

installation and environmental effects resulted in the failure of some of these connections.

Thorough investigations are ongoing and have led to updated improved guidelines on the design of

grouted connections. Applying these guidelines and using extensive quality control during execution

of the works should prevent failures of grouted connections in the future. Bolted connections can be

used as an alternative but have other drawbacks.

Synthetic ropes have been used extensively in the permanent mooring systems of offshore

equipment for several decades. Given their relative (compared to steel components) low unit cost,

low unit weight, superior fatigue performance and energy absorbing properties, it is unsurprising

that they have found use in MRE mooring systems. Whilst a great deal can be learnt from the

accrued experience of these components gained by the oil and gas industry, MRE mooring systems

are an entirely new application which present unique challenges, for example dynamically

responsive devices such as WECs. Existing certification and design guidelines may therefore not

account for these differences and it is important that the particularities of these components are

fully considered in this new context at the mooring design stage.

Corrosion in the maritime environment has been well studied and best practices exist regarding the

monitoring and mitigation of corrosion and degradation process for metal and concrete structural

elements caused by chemical and biological process. Corrosion is of particular concern for MRE

devices, because it can contribute to fatigue degradation. Both floating and submerged ocean

energy devices are exposed to the harsh marine environment, including highly corrosive salt water,

in particular in the aerated splash zone, microbiological fouling and marine growth. The rate of

corrosion will vary due to the differing oxygen/moisture content in the various zones. Thicker steel

sections (i.e. corrosion allowances) based on corrosion rates and the design life of the structure can

mitigate the effects of corrosion. Cathodic protection (CP) systems are widely applied in offshore


55


industry. As one of the main challenges for the MRE industry is CAPEX and OPEX reduction,

developers must balance the need to have robust and reliable devices with the costs associated with

implementing mitigation measures (i.e. corrosion protection and allowance). One strategy could be

the use of maintenance free coating systems to avoid expensive marine operations.

Novel mooring and foundation components are starting to be adopted by the MRE industry. Marine

micropile foundations, the novel Exeter tether, bag anchors and innovative connectors have been

presented in this report as examples of new components that may be suitable for MRE applications.

The unique features of these components are presented along with the potential cost and reliability

advantages that may be provided over pre-existing technologies. All the novel components

discussed show the potential to be advantageous for MRE devices however long-term sea trials are

required before the reliability, economic and environmental impact benefits are fully known.

This report has found that assessment of cost and reliability is very specific to the device or system

and given the lack of concurrent methodologies, a number of different methodologies will likely

have to be employed throughout the development of the Design Tool. Of the components that make

up a MRE device a large proportion can, in the global database, be assigned a unit cost or

alternatively unit cost per quantity (i.e. €/metre) which is then multiplied by the required quantity.

The difficulty, which has been illustrated in Section 2 for grout systems, is the estimation of costs

which are highly specific to a procedure (i.e. installation) which is itself dependent on a multitude of

factors (such as varying equipment and vessels costs and weather windows). Prediction of

component reliability is similarly non-trivial and although certain information exists (i.e. the fatigue

performance of synthetic ropes) it may not be totally applicable to MRE devices. Whilst indicative

cost and reliability examples are given in this report, a complete framework for assessing the cost,

reliability and environmental impact of specific components and systems will be outlined in the

forthcoming deliverable D4.6. This document will present the findings from tasks 4.5-4.7 which

investigate the reliability, economics and environmental aspects respectively.


56


7 BIBLIOGRAPHY

A Historical Review on Integrity Issues of Permanent Mooring Systems. (2013). OTC. USA: OTC 24025

May 2013.

ABS. (2011). Guidance Notes on the Application of Fiber Rope for Offshore Mooring. American

Bureau of Shipping.

ABS. (2011). THE APPLICATION OF FIBER ROPE FOR OFFSHORE MOORING. USA: American Bureau of

Shipping.

API. (2005). Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating

Structures. Third Edition. API RP 2SK. USA: American Petroleum Institute.

Aquatera. (2012). Guide to technical components relevant to wave and tidal energy. UK: Scottish

Government.

Banfield, SJ, Casey, NF and Nataraja. (2005). Durability of polyester deepwater mooring rope. OTC (p.

OCT17510). USA: Offshore Technology Conference.

BV. (2012). Classification of Mooring Systems for Permanent Offshore Units. NR493DTR02E. Bureau

Veritas.

C.R.Chaplin, A.E. Potts and A. Curtis. (2008). Degradation of wire rope mooring lines in SE Asian

waters. Kuala Lumpur: Offshore Asia 2008.

Carbon Trust and Black & Veatch. (2011). Carbon Trust and Black & Veatch (2011) AcceleThe

potential for cost reduction – insights from the Carbon Trust Marine Energy Accelerator.

Carbon-Trust. (2007). Mooring systems, anchors and intermediate components (MOSAIC). Carbon

Trust.

Carbon-Trust. (2010). Moorings and anchors for wave energy devices. Carbon Trust.

Carbon-Trust. (2014). Testing, qualification and commercialisation of advanced mooring system for

wave and tidal arrays. Carbon Trust Marine Renewables Commercialisation Fund (MRCF).

Carbon-Trust. (2014). Testing, qualification and commercialisation of advanced mooring system for

wave and tidal arrays. UK: Carbon Trust Marine Renewables Commercialisation Fund

(MRCF).


57


Casey, NF and Banfield, SJ. (2005). Factors affecting the measurement of axial stiffness of polyester

deepwater mooring rope under sinusoidal loading. Proceedings of the Offshore Technology

Conference. Houston, USA: OTC 17608.

Celine Lechat, A.R. Bunsell, P. Davies, C.J. Burgoyne. (2008). Characterisation of long term behaviour

of polyester fibres and fibre assemblies for offshore mooring lines. UK: Oilfield Engineering

with Polymers 2008, 7-8 October 2008, Cavendish Conference Centre.

Chailleux E and Davies P. (2003). Modelling the Non-Linear Viscoelastic and Viscoplastic Behaviour of

Aramid Fibre Yarns. Mechanics of Time-Dependent Materials, 291-303.

Chailleux, E., Davies, P. (2003). Modelling the Non-Linear Viscoelastic and Viscoplastic Behaviour of

Aramid Fibre Yarns. Mechanics of Time-Dependent Materials 7, 291–303.

Cordage Institute. (2009). Test Method for Yarn-on-Yarn Abrasion, Wet and Dry. Test Method CI

1503-09.

Cordage Institute. (2013). Performance Requirements for Marine Grade Nylon Yarn for Fiber Rope. CI

Guideline 2009N.

da Costas Mattos, HS and Chimisso, FEG. (2011). Modelling creep tests in HMPE fibres used in ultra-

deep-sea mooring ropes. International Journal of Solids and Structures, 144-152.

Dallas J. Meggitt, Jon Machin, Eric Jackson and Robert Taylor. (2013). Marine Micropile Anchor

Systems for Marine Renewable Energy Applications. 978-0-933957-40-4 © 2013 MTS.

DNV. (2005). Recommended Practice - Damage assessment of fibre ropes for offshore mooring

guideline. Norway: Det Norske Veritas, DNV-RP-E304.

DNV. (2006). MATERIAL RISK - AGEING OFFSHORE. Norway: DET NORSKE VERITAS, REPORT NO.

2006-3496.

DNV. (2010). Offshore Standard – Position Mooring. DNV-OS-E301. Norway: Det Norske Veritas.

DNV. (2010). Summary Report from the JIP on the Capacity of Grouted Connections in Offshore Wind

Turbine Structures. Norway: Det Norske Veritas.

DNV. (2011). Design of Offshore Wind Turbine Structures. Norway: DET NORSKE VERITAS AS, DNV-

OS-J101.

DNV. (2011). SYROPE JIPGlobal Performance of Synthetic Rope Mooring Systems. Norway: DNV.


58


DNV. (2012). Offshore Service Specification - Certification of Tidal and Wave Energy Converters. DNV-

OSS-213. Norway: Det Norske Veritas.

DNV. (2013). Offshore Standard – Offshore Fibre Ropes. DNV-OS-E303. Norway: Det Norske Veritas.

DNV. (2013). Certification of Grouted Connections for Offshore Wind Turbines. Norway: Det Norske

Veritas, 04/12/2013.

DNV.GL. (2011). New design practices for offshore wind turbine structures. Retrieved from

http://www.dnv.com/press_area/press_releases/2011/new_design_practices_offshore_win

d_turbine_structures.asp.

Duggal, O. D. (2010). Analysis, Design and Installation of Polyester Rope Mooring systems in Deep

Water. USA: OTC.

EMEC. (2009). Guidelines for Design Basis of Marine Energy Conversion Systems. UL: BSI, 389

Chiswick High Road, London W4 4AL.

Flory JF, Leech CM, Banfield SJ and Petruska DJ. (2005). Computer Model to Predict Long-Term

Performance of Fiber Rope Mooring Lines. Offshore Technology Conference. Houston, USA:

OTC17592.

Flory, J and Banfield, SJ. (2006). Durability of Polyester Ropes Used as Deepwater Mooring Lines.

OCEANS 2006. Boston, USA: Proceedings of OCEANS 2006.

François, M., Davies, P., Grosjean, F., Legerstee, F. (2010). Modelling of fibre rope load-elongation

properties - Polyester and other fibres. Proceedings of the 2010 Offshore Technology

Conference. Houston, USA: OTC 20846.

Ghoreishi, S.R., Cartraud, P., Davies, P. and Messager, T. (2007). Analytical modeling of synthetic

fiber ropes subjected to axial loads. Part I: A new continuum model for multilayered fibrous

structures. International Journal of Solids and Structures, 2924-2942.

Gordelier T, Parish D and Johanning L. (2014). A novel mooring tether for highly dynamic offshore

applications; mitigating peak and fatigue loads via reduced and selectable axial stiffness.

IEC. (2014). Marine energy - Wave, tidal and other water current converters - Part 10: The

assessment of mooring system for marine energy converters. IEC-TS 62600-10 Ed.1.0 (In-

Progress). International Electrotechnical Commission.


59


Inge Lotsberg, Andrzej Serednicki, Håkon Bertnes and Andreas Lervik. (2012). Design of grouted

connections for monopile offshore structures,Results from two Joint Industry Projects .

General & Introductory Civil Engineering & Construction, John Wiley & Sons, DOI:

10.1002/stab.201201598.

International Marine Forum. (2000). Guidelines for the purchasing and testing of SPM hawsers.

Johanning, L. and Smith, G.H. and Wolfram, J. (2007). Measurements of static and dynamic mooring

line damping and their importance for floating WEC devices. Ocean Engineering, 1918-1934.

Kirrane P, Fabricius P and Morvan R. (2010). Kirrane Development of an Efficient Design Technique

for the Optimisation of Mooring Systems for Wave Energy Arrays.

Knudsen, O. Ø. (2010). Evaluation of existing coatings for corrosion protection of structural

components. Norway: SINTEF Materials and Chemistry.

L. Castro-Santos, S. F.-C. (2013). Methodology to calculate mooring and anchoring costs of floating

offshore wind devices. International Conference on Renewable Energies and Power Quality.

Bilbao, Spain: ISSN 2172-038.

Lea, F. M. (1970). The Chemistry of cement and Concrete. New York, NY: Chemical Publishing

Company.

Ma, K-t, Duggal A, Smedley, L'Hostis D and Shu H. (2013). A Historical Review on Integrity Issues of

Permanent Mooring Systems. Offshore Technology Conference (OTC 24025). USA: Offshore

Technology Conference (OTC 24025).

McKenna, HA, Hearle, JWS. and O’Hear, N. (2004). Handbook of Fibre Rope Technology . Woodhead

Publishing Limited.

Noble-Denton. (2006). Floating production system JIP FPS mooring integrity. Noble Denton Europe

Limited, Research Report 444 prepared for the Health & Safety Executive.

NORSOK. (2009). Marine fish farms - Requirements for site survey, risk analyses, design,

dimensioning, production, installation and operation. NS 9415.E:2009. Norway: Norske

Standard.

Overington, MS and Leech, CM. (1997). Modelling Heat Buildup In Large Polyester Ropes .

International Journal of Offshore and Polar Engineering, 7(1).


60


P. Jean, K. Goessens, D. L’Hostis. (2005). Failure of Chains by Bending on Deepwater Mooring

systems. OTC. USA: OTC 17238, May 2005.

Parish-Johanning. (2012). Patent No. PCT/IB2011/050206. USA.

PCT/IB2011/05020, P. D. (n.d.).

Ridge, I.M.L., Banfield, S.J. and Mackay, J. (2010). Nylon Fibre Rope Moorings for Wave Energy

Converters. OCEANS 2010 . Seattle, USA: In Proceedings of the OCEANS 2010 conference.

S. A. Mavrakos, V. J. (1996). Deep Water Mooring Dynamics. Marine Structures 9, 181-209.

S. Weller, P. Davies, L. Johanning. (2013). The Influence of Load History on Synthetic Rope. Denmark:

EWETEC.

SI-Ocean. (2013). Ocean Energy: Cost of Energy and Cost Reduction Opportunities. SI Ocean.

Taylor, H. F. (1990). Cement Chemistry. London : Thomas Telford.

Terry Crump, Kris Volpenhein, Dennis Sherman & Rafael Chou. (2008). Abrasion and Fibre Fatigue in

High Performance Synthetic Ropes for Ship Escort and Berthing. USA: Suntec Convention

Centre, Singapore Organised by the ABR Company Ltd.

Thies, PR, Johanning, L, Harnois, V, Smith, HCM and Parish, DN. (2014). Mooring line fatigue damage

evaluation for floating marine energy converters: Field Measurements and prediction.

Renewable Energy, 63, 133-144.

TTI. (2002). Examination and Investigation to Establish Cause of Failure of Polyester Rope. UK: TTI.

TTI. (2009). Design and engineering study for wave energy device.

Weller SD, Davies P, Vickers AW, and Johanning, L. (2014). Synthetic Rope Responses in the Context

of Load History: Operational Performance. Ocean Engineering, 111-124.


61


8 ACRONYMS

ALS Accidental Limit State CA Corrosion Allowance CAPEX Capital Expenditure CP Cathodic Protection CRA Corrosion Resistance Alloys HISC Hydrogen Induced Stress Cracking HMPE High modulus polyethylene MRE Marine Renewable Energy OPEX Operating Expenditure QA Quality Assurance QC Quality Control TCLL Thousand Cycle Load Level Test TSA Thermally Sprayed Aluminium ULS Ultimate Limit state WP Work Package

deliverable 4.3: report on suitability of assessment ... · figure 5-1: micropile, courtesy of...

Documents