1

Corrosion Damage Effects on the Structural Integrity Assessment of

Offshore Structures

Sabina AGHASIBAYLI1, Prof Feargal BRENNAN2

1University of Strathclyde, Glasgow, United Kingdom, sabina.aghasibayli@strath.ac.uk

2University of Strathclyde, Glasgow, United Kingdom, feargal.brennan@strath.ac.uk

Abstract

One of the biggest and most expensive challenges for the offshore wind power sector is corrosion

degradation of offshore structures. Many offshore wind foundations were installed with inadequate

corrosion protection and remedial management plans rely heavily on practices from the oil and gas

sector. These are not always appropriate given the differences in cost, damage tolerance and structural

reliability between the two sectors. Consequently, suboptimal corrosion protection and management

can result in unexpected failures that lower the design life, increase interventions and result in significant

adverse financial consequences.

This paper aims to provide a brief overview on corrosion of the offshore wind turbine foundations.

Corrosion types most commonly occurring in the offshore wind foundations and preferential locations

are discussed. The importance of in-depth corrosion study of welded structural carbon steel is

emphasized.

Keywords

Offshore wind turbine, carbon steel, S355, marine environment, artificial seawater, pitting, MIC, weld

2

Introduction

With the growing green energy demand, United Kingdom (UK) government announced a new

renewable target: by 2030 nearly third of all electricity to come from offshore wind power [1].

Thus for further development of offshore wind sector and achieving ambitious targets, it is

important to make the offshore wind sector favourable for investors and further decrease the

levelised cost of energy (LCOE).

LCOE largely depends on the capital expenditure (CAPEX), operational expenditure (OPEX)

and design life of an asset. Thus, appropriate alterations and optimisations in current

construction and installation, inspection and maintenance techniques would reduce the current

LCOE.

Majority of the offshore wind turbines are designed for operational life of 20 years with a

potential for life-extension. Naturally, it would be possible to prolong the life of the structure if

it is meeting reliability criteria and further operation of the turbine is financially feasible taking

into account additional operations and maintenance (O&M) costs. Competent design, timely

inspection and maintenance can make life-extension of the structure possible and ultimately

contribute to lowering of the LCoE.

Offshore wind turbine (OWT) foundations are subjected to aggressive marine environment and

experience enormous loads from wind and waves. The integrity of structures is at constant

threat. It requires millions of pounds yearly to control and mitigate the results of structural

degradation due to corrosion and fatigue. Consequently, corrosion degradation becomes one of

the biggest and most expensive challenges for the offshore wind power sector.

Figure 1. Industry challenges, gaps in current knowledge and consequences of the above

mentioned factors in OW industry

Unavailability of long-term data on corrosion and fatigue prevents from creating an explicit

prediction model causing over-design of structures. Many offshore wind foundations were

installed with inadequate corrosion protection and remedial management plans rely heavily on

practices from the oil and gas sector, which are not always appropriate given the differences in

3

cost, damage tolerance and structural reliability between the two sectors. Moreover, limitation

of inspections methods as well as a high cost puts the integrity of offshore structures in a big

risk.

Consequently, suboptimal corrosion protection and management can result in unexpected

failures that can pose both life and environmental threat, lower the design life, increase

interventions, negatively affect public opinion, cause energy supply problem and finally result

in significant adverse financial consequences.

This paper summarises essential information regarding corrosion aspects in offshore wind

turbine structure. Brief information is given on the following subjects:

Offshore Wind Turbines Structures (monopiles)

Corrosion of Offshore Wind structures: uniform, pitting and microbiologically

influenced corrosion (MIC)

Corrosion preferential locations and protection

Table 1. List of abbreviations and acronyms

BM Base metal

CAPEX Capital expenditure

CP Cathodic protection

DO Dissolved oxygen

HAZ Heat affected zone

HS High strength steel

LCOE Levelised cost of energy

MIC Microbial corrosion, microbiologically influenced corrosion, or microbially

induced corrosion

MP Monopile

NS Normal strength steel

O&M Operations and maintenance

OPEX Operational expenditure

OW Offshore wind

OWS Offshore wind structure

OWT Offshore wind turbine

PM Parent material

RNA Rotor nacelle assembly

SMYS Specified minimum yield strength

SRB Sulphate-reducing bacteria

WM Weld metal

WT Wind turbines

4

Literature Review

Offshore Wind Turbines Structures

Offshore wind turbines can be classified by the type of foundation: bottom-fixed and floating.

Within bottom fixed type of foundation, monopile and piled jacket foundations are the most

common types found in the offshore wind industry today (Figure 2).

Figure 2. Different types of support structures. Adapted from [2].

Figure 3. Basic components of offshore wind turbine with monopile foundation.

Conventional three-blade bottom-fixed offshore wind turbine (WT) comprises support structure

and rotor nacelle assembly (RNA). Support structure includes foundation, sub-structure

(transition piece) and tower (Figure 3). It provides structural integrity to the RNA and transfers

the aerodynamic and environmental loads acting on the structure down to the seabed. RNA

accommodates the power generating components and comprised of blades, hub and nacelle.

5

Monopile (MP) structures are favoured for its straightforward design and relatively simple and

inexpensive fabrication and installation. Subsequently, as the industry is pushing for larger

capacity turbines, deeper waters and lower LCOE, monopile structure remains a cost-effective

solution.

MP foundation is a single large diameter pile fabricated from multiple circumferentially welded

steel cans. Each can is made from cold-rolled thick carbon steel plates and longitudinally

welded.

Certainly, the choice of material is greatly affecting the degree of structural degradation of

OWT. Considering the size of turbines, the use of any corrosion resistant materials and alloys

in such quantities would be financially impractical. Currently dimensions of the monopile could

reach up to 10 m in diameter with plate thickness reaching 150 mm [3]. Thus, monopile support

structure for OWT is typically manufactured from inexpensive low alloy carbon steel grade

S355.

DNV-GL standard suggests a range of carbon steel grades with different strengths; and the

selection of material should be adequate to fulfil the requirements of a specific project [4]. The

low alloy carbon steel is divided into three categories depending on the strength of the steel:

Normal strength steel (NS) includes S235;

High strength steel (HS) contains S275 and S355;

And finally, the extra high strength steel has S420 and S460 [4].

The steel is designated according to the European standard where the letter represent the

application of the steel and the number represent specified minimum yield strength (SMYS) for

the smallest thickness in MPa [5].

The chemical compositions of S355 and the mechanical properties vary depending on the sub-

grade and the thickness of the product. The detailed chemical compositions and mechanical

properties of S355 are specified in the standard EN 10025 where the maximum allowable

carbon equivalent varies between 0.39% - 0.49% and the SMYS between 355 – 265 MPa

depending on the sub-grade and thickness [6],[7],[8],[9].

As the industry grows bigger, the use of higher strength steel types in the future is obvious.

However, it is important to note that these types of steels (SMYS>550 N/mm2) are prone to

hydrogen embrittlement, unlike S355 grade steel [10].

Corrosion of Offshore Wind Support Structure

Offshore wind turbines structures are subjected to the aggressive seawater environment,

temperature cycles, tidal fluctuations and variable cyclic load due to wave and wind impact.

Consequently, corrosion and fatigue damages are the potential causes of structural degradation

of the turbine. Untimely failures occur even with the application of corrosion protection

methods and performing regular inspections and maintenance.

Corrosion mechanism and degradation rates are greatly affected by the composition and

physical characteristics of the corrosive medium (seawater). Currently most of the offshore

wind turbines are installed in open sea or in coastal waters.

6

Natural seawater is a complex system consisting of a unique chemical combination of inorganic

and organic compounds and countless types of living organisms. Despite site-specific nature of

seawater composition, “ratios of the concentrations of the major constituents are remarkable

constant worldwide” (Error! Reference source not found.); and they “account for 99.95% of

the total solutes” [11]. Seawater is lightly alkaline with pH varying from 7.8 to 8.3, while

surface waters are usually more alkaline with pH greater than 8.

Chemical and biological profile of open seas and coastal water can significantly differ. Coastal

waters are often polluted due to human activities and become a more aggressive environment

for structures. Industrial, domestic and farming waste, and marine transport pollution introduce

heavy metal ions, nutrients, organic matter etc. in marine habitat [11]. Consequently, metal

degradation can occur through different corrosion mechanism.

Table 2. Concentrations of major constituents in seawater (35‰ salinity; 1023 kg/m3 density,

temperature 25˚C) [11]

Concentration

mmol kg-1 g kg-1

Cat

ions

Na+ 468.500 10.7700

K+ 10.210 0.3990

Mg2+ 53.080 1.2900

Ca2+ 10.280 0.4121

Sr2+ 0.090 0.0079

Anio

ns

Cl- 545.900 19.3540

Br- 0.842 0.0673

F- 0.068 0.0013

HCO3- 2.300 0.1400

SO42- 28.230 2.7120

B(OH)3 0.416 0.0257

Artificially simulated seawater is often used for corrosion testing in laboratory. Synthetic

solution is prepared from “inorganic salts in proportions and concentrations representative of

ocean water” [12]. Artificial seawater, though chemically comparable with natural seawater,

lacks any living organisms and organic agents. In some cases, organic matter and independently

cultivated microorganisms can be added separately into synthetic solution [13]. In addition, the

composition of calcareous deposits on the metal surface in synthetic seawater deviate from that

forming in natural marine environment [14]. Regardless of methodology and solution used,

artificial seawater does not fully represent the aggressive marine environment, especially for

long-term corrosion degradation.

While the use of transported natural stored and/or recirculated seawater brings the corrosion

testing a step closer to recreating the real-life conditions offshore, it is important to note that

corrosion data obtained in such solution may significantly differ from the in-situ testing [11].

With time, the characteristics of stored seawater are probable to transform, e.g. pH values,

concentration of dissolved oxygen (DO), temperature profile, living organisms. In addition,

recirculated seawater may cause continuous accumulation of rust in the system, affecting the

test results.

In a word, replicating marine environment for corrosion testing is a challenging task.

Fluctuations in seawater composition due to geographical location, depth, season, pollution etc.

even further complicates the corrosion prediction and modelling. Attention should be given to

7

corrosion data collected in various mediums, e.g. synthetic seawater, natural stored seawater

etc., before extrapolation to long-term prognosis of corrosion in offshore conditions.

There are different types of corrosion occurring on carbon steel surface in marine environment.

They are typically classified by attack mechanism or visual appearance. Most common

corrosion forms are listed below (Table 3). However, this paper is focusing on uniform, pitting

and MIC corrosion types.

Table 3. Corrosion types in OWT

Uniform corrosion Uniform dissolution of the metal in the environment (atmosphere,

seawater, soil etc.)

Pitting corrosion

Type of a localised attack when local metal dissolution leads to

formation of small cavities on the surface of the metal. In extreme

cases, pitting corrosion may cause through thickness perforation.

Microbially induced

corrosion (MIC)

Type of corrosion influenced by the products of bacterial

metabolism, e.g. hydrogen sulphide production by sulfate-reducing

bacteria (SRB). Form of attack is often pitting.

Corrosion fatigue

and cracking

Material deterioration occurs due to the effects of fatigue and

corrosion attack. Fatigue is the material degradation due to cycling

loading. Fatigue is associated with crack initiation and propagation,

preferentially from the pits acting as a stress concentration areas.

Crevice corrosion

Type of localised corrosion that occurs due to formation of

gaps/crevices. This leads to development of differential aeration

cells that trigger metal dissolution.

Galvanic corrosion Also called bimetallic corrosion. Attack occurs due to

electrochemical reaction between dissimilar metals in electrolyte.

Erosion corrosion Material thinning occurs due to abrasive action of waves, solid

particles, wind.

Currently, the most successful model describing corrosion progression is proposed by Robert

E. Melchers (University of Newcastle, Australia). The model is applicable to uniform

dissolution in terms of mass loss and localised corrosion in terms of pit depth, and it is valid for

corrosion in seawater and soils [15], [16]. Figure 4 illustrates the basic concept of the model.

Each phase is described in Table 4.

8

Figure 4. Graphical representation of the Melcher's bi-modal model [15].

Table 4. Corrosion phases in Melcher's bi-modal model [15], [17], [18].

Phase 0

Kinetic controlled

oxidation and

MIC

Short phase following near-linear function. This phase is

controlled by the kinetics of oxidation. Initiation of rust

layer and biofilm growth.

Phase 1

Concentration

controlled

oxidation

Corrosion in this phase depends on the amount of available

oxygen near the surface.

Phase 2

Diffusion

controlled

oxidation and

polarisation

As rust and biofilm starts to thicken on the surface of the

metal, the concentration of oxygen that can penetrate

through the barrier becomes restricted. Thus, the oxidation

process becomes restrained by the diffusion of oxygen. The

corrosion rate is gradually reducing.

Phase 3 Bacterial

influence

Just as the layer becomes thicker, oxygen depleted zones

start to develop inside the deposit. Corrosion rates are first

sharply increasing, due to microbiological activity (e.g.

SRB).

Phase 4 Steady state

With time, corrosion rates are gradually decreasing

establishing a steady dissolution. The function is near-

linear.

The point “ta” on the graph (Figure 4) represents a change from mainly aerobic mode (Phases

0-2) to predominantly anoxic mode (Phases 3 and 4). Corrosion progression in phases 0-2 can

take years in low temperature waters, e.g. about 3 years in North Sea. While in tropical regions

phase three starts in less than a year [19]. It is important to note, that in case of large seasonal

temperature change the corrosion rates should not be directly extrapolated for long-term

corrosion (Figure 5).

9

Figure 5. Melcher's model: corrosion loss vs time showing effect of seasonal temperature on

corrosion. [17]

The scientific term “pitting corrosion” is associated with a local rupture of metal’s passive film

in aggressive environment and formation of a pit due to metal dissolution inside, while the rest

of the surface remains free of corrosion [20]. For carbon steel, which does not form a protective

oxide layer, “pitting” is a localised corrosion attack that takes a form of a cavity on the metal

surface. These pits can be originated from pitting corrosion, MIC or erosion corrosion.

According to [18] pits initiate and propagate at different moments in time; the propagation rate

also varies from pit to pit; and pitting mechanism may differ with time due to local change of

conditions, e.g. biofilm and rust layer development, micro-environment formation, etc.

The mechanism of pitting attack is still widely uncertain. However, the fact that Melcher’s

model also works for corrosion in fresh distilled water, raises an interesting point that

degradation of metal occurs according to bi-modal behaviour regardless of availability of

microorganisms and chlorides in water. In abiotic water during oxygen-controlled mode, a non-

uniform rust layer is forming on the surface causing formation of oxygen-depleted zones within

the layer. Pitting corrosion in these anoxic regions is forming due to MnS inclusion [21]. In

case of biologically active waters, the localised corrosion is worsen by anaerobic

microorganisms flourishing in anoxic nooks [15]. Moreover, research by [22] suggests that pits

form in areas with high tensile residual stresses that act as anodic regions.

Figure 6 illustrates the growth model of pits, described in detail in [23]. Pits typically start with

growing in depth, later coalescing with neighbouring pits eventually forming wide shallower

pits (macro pitting). New pits now start to develop at the bottom of joined pits (micro-pits). The

rate of pit growth is proportional to time following the law: pit size ~ t1/3 [24]. This formation

is largely influenced by the products of bacterial metabolism in anaerobic conditions. It is

reasonable to state, that for offshore structures such “stepped bench” topography are very

dangerous when paired with fatigue degradation [25].

10

Figure 6. Proposed model of pitting growth. [23]

The significant effect of marine biofouling and bacterial activity on the severity of corrosion is

long known. Attachment of living marine organisms, such as oysters, mussels, barnacles, algae,

seaweeds etc., on the surface of immersed structures is called macro-fouling. Micro-fouling

refers to formation of slimes due to bacteriological activity. The metal degradation occurs due

to damaging effect of attachment and/or products of bacterial metabolism.

Bacteria, most commonly held responsible for corrosion of carbon steel in marine environment,

are sulphate-reducing bacteria (SRB). In oxygen depleted zones, e.g. under deposits, in anoxic

waters, SRB flourish reducing sulphur compounds (sulphates, sulphites etc.) to hydrogen

sulphide (H2S). Introduction of such aggressive compounds in the system leads to formation of

pits [26], [27].

Corrosion preferential locations and protection

The choice of corrosion protection method completely depends on the exposure area of the

structure. These areas on offshore structure can be classified into the following zones:

atmospheric, splash, tidal, submerged and buried zone (Figure 7).

Figure 7. Relative loss of metal thickness of unprotected steel on offshore wind turbine

structure in seawater. Adapted from [28].

11

Zone 1

Atmospheric corrosion

Atmospheric zone is associated with little corrosion caused by

seawater droplets containing marine salts, i.e. seawater spray.

This area is protected by coating.

Corrosion rates 0.050-0.075 mm/year [29].

Zone 2

Splash zone

Splash zone is prone to severe corrosion degradation due to

continuous wetting and drying processes and wave effect. Pits

formed in this area are typically deep [30]. The external area is

always protected by coating and corrosion allowance; internally

– by corrosion allowance and optionally by coating.

Corrosion rates 0.20-0.40 mm/year [29].

Zone 3

Tidal zone

This area as well is experiencing recurring wetting and drying

processes and wave action. It is usually protected by coating,

corrosion allowance and cathodic protection when immersed.

Corrosion rates 0.05-0.25 mm/year [29] with localised corrosion

rates up to 0.50 mm/year [31].

Zone 4

Submerged zone

The external areas of the offshore structure must be protected by

means of cathodic protection. Internally the surface should be

protected by corrosion allowance and/or cathodic protection.

Coating can be adopted if necessary.

Pits in immersed zones are usually broad and shallow with

growth rates 0.20-0.30 mm/year [30]. Uniform corrosion rates

0.10-0.20 mm/year [29].

Zone 5

Buried zone

Areas of structure buried in seabed. Uniform corrosion with low

dissolutions rates is assumed, however it has been found that this

zone is prone to localised corrosion at the mudline. Currently

there are no guidelines for protection of buried areas, though CP

may be used if adequately designed [32].

Corrosion rates of 0.06-0.10 mm/year are expected [29],

however [31] reports possible pitting rates up to 0.25 mm/year.

According to DNVGL-RP-0416 Standard, the minimum corrosion rate for submersible part is

0.10 mm/year for internal surfaces and 0.30 mm/year for external (applicable to North Sea

area). While minimum corrosion rates in warmer regions of the globe, e.g. sub-tropical and

tropical, are expected to be 0.20 mm/year for internal and 0.40 mm/year for external surfaces

[33]. Although some report corrosion values of 2.5 mm/year for carbon steels [34].

Initially it was believed that internal compartments are perfectly sealed and airtight, preventing

ingress of oxygen and aerated seawater. Consequently, all available oxygen would be

eventually consumed causing uniform metal dissolution with low corrosion rates and, at last,

the environment would become anaerobic. Thus, in earlier version of DNVGL-RP-0416

Standard no corrosion protection was applied for internal parts of the offshore wind turbine.

However practically, J-tube seals and grout connections fail and airtight compartments are

systematically accessed. Hence, internal compartments are experiencing excessive corrosion,

making earlier corrosion estimations no longer valid [35]. Moreover, during the installation,

12

foundations are often left in seawater without any corrosion protection (except corrosion

allowance) for up to 12 months. While, fatigue life cycle calculations on the design stage are

not taking into account a free-corrosion period of the structure.

Figure 8 illustrates some current problems arising in the OWT structure, areas suffering from

corrosion and types of metal degradation with each case being discussed below.

Figure 8. Types of corrosion and its preferential locations in OWT. Adapted from [36]

Splash zone Prone to severe material degradation due to continuous wetting and drying.

Always protected by coating (externally).

Waterline Uniform and localised corrosion (MIC, pitting) appears on the surface of

metal due to formation of macrogalvanic element (i.e. differential aeration

cell), especially in case of stagnant water condition. In comparison, lower

parts of the monopile usually suffer less from the corrosion.

13

Weldments Welding process alters the microstructure, introduces defects and residual

stresses in the material. Weld and heat affected zone (HAZ) are prone to

corrosion pitting and fatigue cracking. Weldments are considered weak

points of the structure and often are roots of failure.[37]

Unprotected

surface

As a result of uncoated surfaces (external and internal) and often insufficient

cathodic protection, unprotected metal is suffering from uniform and

localised attack. Free-corrosion conditions.

J-tube cable

entry

Imminently with time, the cable entry seal fails and aerated seawater enters

the structure, increasing the overall corrosion rate. The water replenishment

changes the chemical and biological environment inside the monopile. Tidal

variations may occur inside the monopile, changing the water level inside on

a regular basis. Significant increase in oxygen levels is expected at the cable

entrance.

Build-up of

gasses and

acidifying

Presence of certain bacteria, e.g. sulphate-reducing bacteria (SRB), in

seawater and seamud does not only induce the corrosion rates and cause

severe pitting, but also causes formation of hydrogen sulphide gas (H2S). The

oxygen depletion inside the monopile can trigger excessive production of

hydrogen sulphide [38]. Moreover, inadequate CP installation can cause

hydrogen (H2) gas accumulation in the internal parts of the WT putting the

whole asset in danger of explosion. Usage of sacrificial aluminium anodes

and formation H2S may promote acidification of the water inside the

monopile. To avoid that, replenishment of water and venting is required

inside the monopile. [10]

Grouted

connection

The gap between the monopile and transition piece is normally filled with

cement grout. In course of time due to constant variable loading, inadequate

grouting design, high friction, settlement of TP a number of OWT have

shown to experience grouting failure, such as cracking. This issue poses a

risk of possible ingress of oxygen and aerated seawater. Current projects have

adopted different design approach to avoid this problem [36].

Stagnant

water

Stagnant water conditions are formed in many OWT monopile foundations.

It causes development of unique environment, which prevents any adequate

predictions of the corrosion mechanism and rates to be made.

Insufficient

cathodic

protection

In the majority of projects, galvanic (sacrificial) anode based cathodic

protection is used for external and internal parts of the WT. The common

problems with CP are usually the following: erroneous current demand

calculations, current drainage, lack of experience and knowledge, distance

from anodes and coverage of a large structure, premature anode dissolution

due to harsh environment and inaccurate design.[39]

14

Mud zone Mud line zone is expected to have low general corrosion rates of ~0.015

mm/year. However, this area is at high risk of macrogalvanic element (i.e.

differential aeration cell) formation, as well as MIC due to biologically active

soil and seawater, i.e. localised corrosion [40]. Consequently, development

of pits induces the possibility of fatigue cracking development. Mudline

corrosion while posing a high risk to structural integrity has received little

attention in scientific research and industry practice. This area is almost never

inspected in real-life. [32]

Current ways of corrosion mitigation in OW industry include corrosion allowance, application

of cathodic protection (CP), coating/painting as well as regular inspection and, if possible,

monitoring [29]. Nowadays, companies become more invested in using monitoring systems,

such as SHM, as a way to replace/reduce inspection [47].

Albeit many advantages of the impressed current cathodic protection, the use of galvanic

sacrificial anodes is a most preferred choice in industry [41]. Standard practices for CP for

external parts of offshore structures are well proven by decades of experience in oil and gas

sector. The use of CP for monopile internal compartment poses a number of challenges.

Inadequate CP installation and confined space are major reasons for acidification of water

column, gases build-up, and accelerated corrosion [42]. It has been found, that replenishment

of water inside the monopile is essential for internal cathodic protection to satisfactorily

function [43].

Inspection offshore is restricted by the high cost, harsh environment, safety regulations and

limitations of current techniques. Much of OWT sections do not get an adequate attention, some

are inaccessible or require special handling. So, mudline of the structure is hardly inspected if

ever. The reliability of this section is fully relying on satisfactory service of cathodic protection.

Typical areas of inspection in offshore almost entirely focus on welds. Despite being an

essential joining technique in fabrication of offshore structure, welding process changes the

microstructure of the welded region, introduces residual stresses and various defects [44].

Welds and specifically HAZ are prone to severe deep pitting [45] [46] that act as stress raisers

and cause fatigue cracking. However, pits are hard to detect, the most effective identification

techniques today are replying on destructive testing methods, which obviously are not

applicable to functioning structures. Consequently, better understanding of pitting formation in

welds is required.

Conclusion

A concise overview of current corrosion state in offshore wind industry has been addressed in

this paper. Respectively, a major question is arising: “What can be done to improve the current

status of corrosion in OWT?”. After all, improved corrosion prediction will result in safe long-

lasting asset exploitation beyond its designed life-span. This will directly lead to reduction in

levelised cost of energy. Knowing when to expect the problem, where to search for it and what

to anticipate, will transform the current inspection schedules, ensure the reliability of asset and

overall improve the O&M. Consequently, it is important to deepen our understanding of

corrosion progression of welded structural carbon steel in seawater under fatigue load in critical

areas of the wind turbine structure.

15

References

[1] “Press Release: Offshore wind energy revolution to provide a third of all UK electricity

by 2030,” Department for Business, Energy & Industrial Strategy and The Rt Hon Claire

Perry MP. [Online]. Available: https://www.gov.uk/government/news/offshore-wind-

energy-revolution-to-provide-a-third-of-all-uk-electricity-by-2030.

[2] S. Rodrigues et al., “A multi-objective optimization framework for offshore wind farm

layouts and electric infrastructures,” Energies, vol. 9, no. 3, pp. 1–42, 2016.

[3] A. Mehmanparast, J. Taylor, F. Brennan, and I. Tavares, “Experimental investigation of

mechanical and fracture properties of offshore wind monopile weldments: SLIC

interlaboratory test results,” Fatigue Fract. Eng. Mater. Struct., vol. 41, no. 12, pp.

2485–2501, 2018.

[4] DNV GL AS, “Standard DNVGL-ST-0126 - Support structures for wind turbines,”

2016.

[5] “BS EN 10027-1 : 2016 Designation systems for steels Part 1: Steel names,” 2016.

[6] “BS EN 10025-3:2004 Hot rolled products of structural steels Part 3: Technical delivery

conditions for normalized/normalized rolled weldable fine grain structural steels,” 2004.

[7] “BS EN 10025-2:2004 Hot rolled products of structural steels Part 2: Technical delivery

conditions for non-alloy structural steels,” 2004.

[8] “BS EN 10025-4:2004 Hot rolled products of structural steels Part 4: Technical delivery

conditions for thermomechanical rolled weldable fine grain structural steels,” 2004.

[9] “BS EN 10025-5:2004 Hot rolled products of structural steels Part 5: Technical delivery

conditions for structural steels with improved atmospheric corrosion resistance,” 2004.

[10] A. R. Black and L. R. Hilbert, “Corrosion monitoring of offshore wind foundation

structures,” EWEA Offshore 2013, no. November, 2013.

[11] F. P. Ijsseling, “A Working Party Report on Marine Corrosion: General guidelines for

corrosion testing of materials for marine applications,” Eur. Fed. Corros. Publ. by Inst.

Met., no. 3, 1989.

[12] ASTM, “ASTM D 1141 – 98 Standard Practice for the Preparation of Substitute Ocean

Water,” vol. 98, no. Reapproved, pp. 1–3, 2003.

[13] B. J. Little, R. I. Ray, and J. S. Lee, “Understanding marine biocorrosion: Experiments

with artificial and natural seawater,” Underst. Biocorrosion Fundam. Appl., vol. 12, no.

0704, pp. 329–340, 2014.

[14] H. Möller, E. T. Boshoff, and H. Froneman, “The corrosion behaviour of a low carbon

steel in natural and synthetic seawaters,” J. South. African Inst. Min. Metall., vol. 106,

no. 8, pp. 585–592, 2006.

[15] R. E. Melchers, “Microbiological and abiotic processes in modelling longer-term marine

corrosion of steel,” Bioelectrochemistry, vol. 97, pp. 89–96, 2014.

[16] R. B. Petersen and R. E. Melchers, “Bi-modal trending for corrosion loss of steels buried

in soils,” Corros. Sci., vol. 137, no. March, pp. 194–203, 2018.

[17] R. E. Melchers, “Modeling of marine immersion corrosion for mild and low-alloy steels

- Part 1: Phenomenological model,” Corrosion, vol. 59, no. 4, pp. 335–344, 2003.

[18] X. Wang and R. E. Melchers, “Long-term under-deposit pitting corrosion of carbon steel

pipes,” Ocean Eng., vol. 133, no. August 2016, pp. 231–243, 2017.

[19] R. E. Melchers, “Long-term immersion corrosion of steels in seawaters with elevated

nutrient concentration,” Corros. Sci., vol. 81, pp. 110–116, 2014.

[20] B. Cottis, M. Graham, R. Lindsay, and S. Lyon, Eds., Shreir’s Corrosion. 2010.

[21] R. Avci, B. H. Davis, M. L. Wolfenden, I. B. Beech, K. Lucas, and D. Paul, “Mechanism

of MnS-mediated pit initiation and propagation in carbon steel in an anaerobic

sulfidogenic media,” Corros. Sci., vol. 76, pp. 267–274, 2013.

16

[22] G. Van Boven, W. Chen, and R. Rogge, “The role of residual stress in neutral pH stress

corrosion cracking of pipeline steels. Part I: Pitting and cracking occurrence,” Acta

Mater., vol. 55, no. 1, pp. 29–42, 2007.

[23] R. Jeffrey and R. E. Melchers, “The changing topography of corroding mild steel

surfaces in seawater,” Corros. Sci., vol. 49, no. 5, pp. 2270–2288, 2007.

[24] Y. Kondo, “Prediction of Fatigue Crack Initiation Life Based on Pit Growth,” Corrosion,

vol. 45, no. 1, pp. 7–11, 1989.

[25] Lotsberg Inge, “11.9 Effect of surface roughness on fatigue strength,” in Fatigue Design

of Marine Structures, 2016, pp. 353–354.

[26] D. Enning and J. Garrelfs, “Corrosion of Iron by Sulfate-Reducing Bacteria: New Views

of an Old Problem,” Appl. Environ. Microbiol., vol. 80, no. 4, pp. 1226–1236, 2014.

[27] M. Stipaničev, F. Turcu, L. Esnault, E. W. Schweitzer, R. Kilian, and R. Basseguy,

“Corrosion behavior of carbon steel in presence of sulfate-reducing bacteria in seawater

environment,” Electrochim. Acta, vol. 113, pp. 390–406, 2013.

[28] Harold T. Michels and C. A. Powell, “Alloys of Copper and Nickel for Splash Zone

Sheathing of Marine Structures,” Copp. Dev. Assoc. Inc., pp. 1–14, 2002.

[29] G. Masi, F. Matteucci, J. Tacq, and A. Balbo, “State of the Art Study on Materials and

Solutions against Corrosion in Offshore Structures,” 2018.

[30] R. Jeffrey and R. E. Melchers, “Corrosion of vertical mild steel strips in seawater,”

Corros. Sci., vol. 51, no. 10, pp. 2291–2297, 2009.

[31] L. R. Hilbert, A. R. Black, F. Andersen, and T. Mathiesen, “Inspection and monitoring

of corrosion inside monopile foundations for offshore wind turbines,” in EUROCORR

2011, 2011, no. 4730.

[32] L. R. Hilbert, T. Mathiesen, A. R. Black, C. Christensen, and F. Technology, “Mud zone

corrosion in offshore renewable energy structures,” Eurocorr 2013, 2013.

[33] DNVGL-RP-0416, DNVGL-RP-0416 Recommended Practice Corrosion protection for

wind turbines (Edition March 2016), no. March. 2016.

[34] S. Price and R. Figueira, “Corrosion Protection Systems and Fatigue Corrosion in

Offshore Wind Structures: Current Status and Future Perspectives,” Coatings, vol. 7, no.

25, 2017.

[35] B. B. Jensen, “Corrosion Protection of Offshore Wind Farms, protecting internal sides

of foundations,” NACE Corros. 2015, no. Paper No. 5762, pp. 1–12, 2015.

[36] T. Mathiesen, A. Black, and F. Grønvold, “Monitoring and Inspection Options for

Evaluating Corrosion in Offshore Wind Foundations,” in NACE Corrosion 2016, 2016,

no. Paper C2016-7702.

[37] M. Jakubowski, “Influence of Pitting Corrosion on Fatigue and Corrosion Fatigue of

Ship and Offshore Structures, Part II: Load - Pit - Crack Interaction,” Polish Marit. Res.,

vol. 22, no. 3, pp. 57–66, 2015.

[38] C. Soraghan, “Management of Hydrogen Sulphide Gas in Wind Turbine Sub-Structures :

identifying and managing H2S,” 2016.

[39] A. R. Black, T. Mathiesen, and L. R. Hilbert, “Corrosion protection of offshore wind

foundations,” NACE Int. Houston, TX, USA, 2005.

[40] P. Refait, A. M. Grolleau, M. Jeannin, E. François, and R. Sabot, “Corrosion of mild

steel at the seawater/sediments interface: Mechanisms and kinetics,” Corros. Sci., vol.

130, no. October 2017, pp. 76–84, 2018.

[41] DNVGL-RP-B401 Cathodic protection design, no. June. 2017.

[42] I. Tavares, P. Ernst, and B. Wyatt, “Internal Cathodic Protection of Offshore Wind

Turbine Monopile Foundations.”

[43] K. Riggs Larsen, “Retrofitting Wind Turbine Monopiles with Cathodic Protection,”

Nace Int. Mater. Perform., vol. 56, no. 8, 2017.

17

[44] N. Stavridou, E. Efthymiou, and C. C. Baniotopoulos, “Welded Connections of Wind

Turbine Towers under Fatigue Loading: Finite Element Analysis and Comparative

Study,” Am. J. Eng. Appl. Sci., vol. 8, no. 4, pp. 489–503, 2015.

[45] I. A. Chaves and R. E. Melchers, “Pitting corrosion in pipeline steel weld zones,” Corros.

Sci., vol. 53, no. 12, pp. 4026–4032, 2011.

[46] Y. Wang, X. Han, Y. Liu, W. Zhang, and L. Niu, “Effect of residual stress on corrosion

sensitivity of carbon steel studied by SECM,” Chem. Res. Chinese Univ., vol. 30, no. 6,

pp. 1022–1027, 2014.

[47] L. Duguid, “Offshore Wind Farm Substructure Monitoring and Inspection Final Report,”

2017.