Loads Analysis of Several 

Offshore Floating Wind Turbine 

Concepts 

A.N. Robertson and J.M. Jonkman 

Presented at the International Society of Offshore and Polar 

Engineers 2011 Conference 

Maui, Hawaii 

June 19-24, 2011 

NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC. 

Conference Paper 

NREL/CP-5000-50539 

October 2011 

Contract No. DE-AC36-08GO28308 
 

 

 

 

 

 

 

 

 

 

 

 

 

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Loads Analysis of Several Offshore Floating Wind Turbine Concepts 

Amy N. Robertson and Jason M. Jonkman 

National Renewable Energy Laboratory
 

Golden, CO, USA
 

ABSTRACT 

This work presents a comprehensive dynamic-response analysis of six 

offshore floating wind turbine concepts. Each of the six models 

contained the same 5-megawatt (MW) turbine. The platforms modeled 

included: a barge, a semisubmersible, two tension-leg platforms (TLP), 

and a spar buoy at two different depths. The performance of these 

models was compared to that of a base model with a turbine supported 

by a fixed land-based tower. Performance was evaluated via a 

comprehensive loads and stability analysis adhering to the procedures 

of the International Electrotechnical Commission (IEC) 61400-3 

offshore wind turbine design standard. The loads in the turbine 

supported by the barge are the highest found for the floating concepts. 

The differences in the loads between the TLP, the semisubmersible, 

and the spar buoy are not significant, except for the loads in the tower, 

which are greater in the spar and semisubmersible systems. The results 

of this analysis will help resolve the fundamental design trade-offs 

between the floating-system concepts. 

KEY WORDS 

Offshore wind turbine; aero-hydro-servo-elastic analysis; tension leg 

platform; spar buoy; barge; semisubmersible 

INTRODUCTION 

Currently, most offshore wind turbines are installed in shallow water on 

bottom-mounted substructures. These substructures include gravity 

bases and monopiles used in water to about 30-meter (m) depth and 

space-frames—such as tripods and lattice frames (e.g., “jackets”)— 

used in water to about 50-m depth. In contrast, harnessing much of the 

vast offshore wind resource potential of the USA, China, Japan, 

Norway, and many other countries requires installations to be located in 

deeper water. At some depth, floating support platforms will be the 

most economical type of support structure to use. 

Numerous floating support-platform configurations are possible for use 

with offshore wind turbines, particularly when considering the variety 

of mooring systems, tanks, and ballast options used in the offshore oil 

and gas (O&G) industry. The platforms, however, can be classified in 

terms of how they achieve basic static stability in pitch and roll. The 

three primary concepts are: the TLP, which maintains stability 

primarily through the mooring system and excess buoyancy; the spar 

buoy, which maintains stability from a deep draft combined with 

ballast; and the barge, which uses a large waterplane area and shallow 

draft to maintain stability. Hybrid systems use a combination of these 

three stability methods. For instance, a semisubmersible is a hybrid 

concept that relies on large waterplane area as well as a fairly deep 

draft and ballasting to maintain stability. 

To help understand the fundamental design trade-offs between the 

different concepts, a quantitative comparison is made between the 

dynamic responses of a variety of floating wind systems. This paper 

examines six floating systems, and compares their performance to a 

wind turbine on land. Three of the floating systems have been 

examined previously in Jonkman and Matha 2010, and the other three 

are generic systems created for a demonstration project led by the 

DeepCwind consortium (www.deepcwind.org) based out of the 

University of Maine (see DeepCwind). The original three concepts 

include the MIT/NREL TLP, the OC3-Hywind Spar, and the ITI 

Energy Barge, which incorporates a concept from each of the three 

primary stability categories. The three new concepts created for the 

University of Maine project include the UMaine TLP, the UMaineHywind Spar, and the UMaine semisubmersible. Both the TLP and 

semisubmersible are very different from the original MIT/NREL TLP 

and barge, but the spar remained the same. The only difference 

between the UMaine-Hywind Spar and the OC3-Hywind Spar is the 

water depth in which the design was analyzed. All University of Maine 

designs are analyzed at a water depth of 200 m, which represents the 

depth of a test site for floating wind turbines off the coast of Maine. 

OVERVIEW OF THE ANALYSIS APPROACH 

The overall design and analysis process applied in this project consists 

of the following steps: 

1.	 Use the same wind turbine specifications—including specifications 

for the rotor, nacelle, tower, and controller—for each system. 

(Minor modifications to the specifications are needed in some 

cases; see Step 2.) Likewise, use the same environmental conditions 

for each analysis—including meteorological (wind) and 

oceanographic (wave), or “metocean,” parameters. Using the same 

1 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

wind turbine specifications and metocean data for all analyses 

enables an “apples-to-apples” comparison of the systems. 

2.	 Determine the properties of each floater, including the platform and 

mooring system designs. To be suitable, each floating platform 

must be developed specifically to support the rotor, nacelle, and 

tower of the wind turbine. In some cases, the wind turbine tower 

might need to be modified in this step to ensure conformity to the 

platform (while maintaining the same hub height). Some platforms 

also require adaptation of the wind turbine control system in this 

step to avoid controller-induced instabilities of the overall system. 

For an explanation of the potential instabilities, see Larsen et al. 

2007 and Jonkman 2007. 

3.	 Develop a model of each complete system within a comprehensive 

simulation tool capable of modeling the coupled dynamic response 

of the system from combined wind and wave loading. 

4.	 Using each full system dynamics model from Step 3, perform a 

comprehensive loads analysis to identify the ultimate loads and 

fatigue loads expected over the lifetime of the system. Loads 

analysis involves running a series of design load cases (DLC) 

covering essential design-driving situations, with variations in 

external conditions and the operational status of the turbine. The 

loads are examined within the primary components of the wind 

turbine, including the blades, drivetrain, nacelle, and tower—and 

for the floating system, the mooring lines. Potential unexpected 

instabilities also can be found in this process. 

5.	 Using the results of Step 4, characterize the dynamic responses of 

the land- and sea-based systems. Comparing the land-based and 

sea-based systems responses enables quantification of the impact 

brought about by the dynamic coupling between the turbine and 

each floating platform in the presence of combined wind and wave 

loading. Comparing the responses of the six sea-based systems with 

each other enables quantification of the impact of the platform 

configuration on the turbine. 

The “Overview of the Analysis Specifications” section describes the 

specifications, data, and procedures used in this project for Step 1, Step 

2, and Step 4. The capabilities of the simulation tool used for this 

project (Step 3) are described in the following section. The results of 

Step 4 and Step 5 are presented in the “Results and Discussion” section. 

SIMULATION TOOL CAPABILITIES 

This work applies the NREL-developed FAST servo-elastic tool 

(Jonkman, 2005), coupled with the AeroDyn rotor aerodynamics 

module (Laino, 2002) and HydroDyn platform hydrodynamics module 

(Jonkman, 2007; Jonkman, 2009a) to enable coupled nonlinear aerohydro-servo-elastic analysis in the time domain. Turbulent-wind inflow 

is prescribed by the external computer program TurbSim (Jonkman et 

al., 2009b). FAST and AeroDyn combined account for the applied 

aerodynamic and gravitational loads, the behavior of the control and 

protection systems, and the structural dynamics of the wind turbine. 

The latter contribution includes the elasticity of the rotor and tower, 

along with the elastic coupling between their motions and the motions 

of the support platform. 

Nonlinear restoring loads from the mooring system are obtained from a 

quasi-static mooring-line module that accounts for the elastic stretching 

of an array of homogenous taut or slack catenary lines with seabed 

interaction. The HydroDyn platform hydrodynamics module accounts 

for linear hydrostatic restoring; nonlinear viscous drag from incidentwave kinematics, sea currents, and platform motion; the added-mass 

and damping contributions from linear wave radiation, including freesurface memory effects; and the incident-wave excitation from linear 

diffraction in regular or irregular seas. HydroDyn requires as input 

hydrodynamic coefficients, including the frequency-domain 

hydrodynamic-added-mass and hydrodynamic-damping matrices and 

wave-excitation force vector. In this work, these hydrodynamic 

coefficients were generated using WAMIT (Lee, 2006), which uses the 

three-dimensional numerical-panel method to solve the linearized 

hydrodynamic radiation and diffraction problems for the interaction of 

surface waves with offshore platforms in the frequency domain. 

OVERVIEW OF THE ANALYSIS SPECIFICATIONS 

To obtain useful information from this conceptual design-and-analysis 

project, use of realistic and standardized input data is required. A large 

collection of input data is needed, including detailed specifications of 

the wind turbine and floating platforms, along with a design basis. A 

design basis consists of analysis methods (discussed above), a 

collection of applicable design standards and load cases, and the sitespecific metocean parameters at a reference site. For this project, the 

specifications of the representative utility-scale multi-megawatt turbine 

known as the “NREL offshore 5-MW baseline wind turbine” were used 

(Jonkman et al., 2009c). The loads and stability analyses were run 

according to the procedures of the IEC 61400-3 offshore wind turbine 

design standard. A location in the northern North Sea was selected as 

the reference site from which to obtain metocean data (Jonkman, 2007). 

Floating Platforms 

Six different floating systems were modeled that support the NREL 5­

MW turbine, with each of the three primary floating platform classes 

being represented. The systems modeled include two different TLP 

systems (the MIT/NREL TLP and the UMaine TLP); a spar buoy 

called the OC3-Hywind spar at two different water depths (the original 

is at 320 m and the UMaine version at 200 m); the UMaine 

semisubmersible; and the ITI Energy barge. All of these floating 

platforms were developed specifically to support the rotor, nacelle, and 

tower of the NREL baseline 5-MW system. Using the same turbine 

system in both the onshore and offshore applications has precedence 

because the design process prescribed in the IEC 61400–3 design 

standard endorses deriving a sea-based wind turbine design from that of 

a land-based wind turbine. 

Each platform is described briefly below. The systems are illustrated in 

Fig. 1 and their properties are summarized in Table 1. Detailed 

specifications are available for the original three designs in Matha 2010 

(for the MIT/NREL TLP), in Jonkman 2009d (for the OC3-Hywind 

spar buoy), and in Jonkman 2007 (for the ITI Energy barge). 

The MIT/NREL TLP is a platform derived from modifications to a TLP 

designed at the Massachusetts Institute of Technology (MIT). It is a 

cylindrical platform, ballasted with concrete and moored by four pairs 

of vertical tendons in tension. Each pair of tendons attaches to a spoke 

that radiates horizontally from the bottom of the platform. The concrete 

ballast is used to ensure that the combined turbine-platform system 

remains stable during float-out—even without the tendons—in mild 

metocean conditions. Note that the platform could have been made 

much smaller without this design feature. The design of the NREL 5­

MW wind turbine remains unchanged when mounted on the 

MIT/NREL TLP. 

2 
3 

Fig. 1. Floating wind turbine design concepts 

The UMaine TLP is a much smaller and lighter system compared to the 

MIT/NREL TLP. It also has a cylindrical platform that is ballasted, but 

has only three legs that protrude from this base. Tensioned vertical 

tendons extend from the tips of each of the legs to the sea bed, to which 

they are anchored. The total tension in these cables due to excess 

buoyancy in the system is less than half the tension in the MIT/NREL 

TLP. The hub height is the same for both TLP systems (87.6 m), but 

the tower properties were modified to conform to the UMaine TLP. 

The controller for the two TLP systems is the same, and is the one used 

for the land-based system as well. The UMaine TLP was created for a 

demonstration project out of the University of Maine, which will build 

a 1/50th scale version and test the system in a wave basin. No 

specifications were given on how a full-scale system would be 

transported at sea. 

The OC3-Hywind spar buoy is a platform that was developed within 

the Offshore Code Comparison Collaboration (OC3), which is a project 

that operated under Subtask 2 of the International Energy Agency 

(IEA) Wind Task 23. The platform imitates the spar-buoy concept 

called “Hywind,” developed by StatoilHydro of Norway, but includes 

adaptations to make it both suitable for supporting the NREL 5-MW 

machinery and appropriate for public dissemination. The system is 

referred to as the “OC3-Hywind” system to distinguish it from 

StatoilHydro’s original Hywind concept. The OC3-Hywind system 

features a deeply drafted, slender spar buoy with three catenary 

mooring lines. The lines attach to the platform via a delta connection 

(or “crowfoot”) to increase the yaw stiffness of the moorings. The 

tower of the NREL 5-MW wind turbine is modified to conform to the 

spar, and the baseline generator-torque and blade-pitch controllers are 

changed to maintain positive aerodynamic damping and to minimize 

rotor-speed excursions when operating above rated wind speed. 

The UMaine-Hywind spar is the same as the OC3-Hywind spar, with 

the exception that it is modeled at a depth of 200 m rather than 320 m, 

which requires slight modifications to the mooring system and the 

modes of the tower. The reason for the change in water depth is that 

the University of Maine demonstration project seeks to examine the 

response of its three generic designs at the same water depth. 

The ITI Energy barge is a preliminary barge concept developed by the 

Department of Naval Architecture and Marine Engineering at the 

Universities of Glasgow and Strathclyde through a contract with ITI 

Energy. The barge is square and is ballasted with seawater to achieve a 

reasonable draft, which is not so shallow that it is susceptible to 

incessant wave slamming. To prevent it from drifting, the platform is 

moored by a system of eight slack, catenary lines. Two of these lines 

emanate from each corner of the bottom of the barge such that they are 

45° apart at the corner. When the NREL 5-MW wind turbine is 

mounted on the ITI Energy barge, the gains in the baseline blade-pitch 

controller are detuned to maintain positive aerodynamic damping when 

operating above rated wind speed. 

The UMaine semisubmersible is a generic model of a semisubmersible 

created for the University of Maine DeepCwind project. It consists of a 

main column attached to the tower and three offset columns that are 

connected to the main column through a series of smaller diameter 

pontoons. Each column starts above the still water line and continues 

beneath the water, with an overall platform draft of 20 m. Catenary 

mooring lines are attached near the base of each of these columns. The 

size and weight of this design are much larger than the other systems. 

Like the barge, the semisubmersible relies mainly on waterplane area to 

achieve stability. But, unlike the barge, it also has a fairly deep draft 

and ballasting for further stabilization. The same controller was used 

for this system as was used for the spars, since the platform-pitch 

frequencies of these systems are similar. 

Load Cases 

A loads and stability analysis was performed for each of the seven 

models, using the IEC 61400-3 offshore wind turbine design standard 

as a guide. Table 2 summarizes the applied DLCs. In this table, the 

DLCs are indicated for each design situation by wind condition, wave 

condition, operational behavior of the control system, fault scenarios, 

and other events. For the land-based cases, the wave conditions were 

discarded and the tower was cantilevered to the ground at its base. 

MIT/NREL 

TLP 

UMaine 

TLP

UMaine 

Spar

OC3-

Hywind Spar

ITI Energy 

Barge

UMaine 

Semi
 

 

 

 

 

 

 

 

 

Table 1. Summary of properties for the six floating platforms 

MIT/NREL 

TLP UMaine TLP OC3-Hywind 

Spar Buoy 

UMaineHywind 

Spar Buoy 

ITI Energy 

Barge 

UMaine SemiSubmersible 

Water Depth (m) 200 200 320 200 150 200 

Diameter or 

width × length (m) 18 6.5 (column) 

15 (tank) 

6.5 to 9.4 

(tapered) 

6.5 to 9.4 

(tapered) 40 × 40 

50 (col. spacing) 

6.5 (main col.) 

12 (offset col.) 

Draft (m) 47.89 24 120 120 4 20 

Water displacement ( m3

) 12,180 2,767 8,029 8,029 6,000 13,990 

Mass, including ballast (kg) 8,600,000 774,940 7,466,000 7,466,000 5,452,000 13,547,000 

CM location of the platform 

below SWL (m) 40.61 19.72 89.92 89.92 0.2818 13.74 

Roll inertia about CM( kg • m2) 571,600,000 150,780,000 4,229,000,000 4,229,000,000 726,900,000 9,139,000,000 

Pitch inertia about CM ( kg • m2) 571,600,000 150,780,000 4,229,000,000 4,229,000,000 726,900,000 9,139,000,000 

Yaw inertia about CM ( kg • m2) 361,400,000 98,850,000 164,200,000 164,200,000 1,454,000,000 16,170,000,000 

Number of mooring lines 8 (4 pairs) 3 3 3 8 3 

Depth to fairleads, anchors 47.89 

200 

28.5 

200 

70 

320 

70 

200 

4 

150 

14 

200 

Radius to fairleads, anchors (m) 27 

27 

30 

30 

5.2 

853.9 

5.2 

445 

28.28 

423.4 

40.87 

837.6 

Unstretched line length (m) 151.7 171.4 902.2 468 473.3 835.4 

Line diameter (m) 0.127 0.222 0.09 0.09 0.0809 0.0766 

Line mass density (kg/m) 116 302.89 77.71 145 130.4 113.4 

Line extensional stiffness (N) 1,500,000,000 7,720,000,000 384,200,000 384,200,000 589,000,000 753,600,000 

Simulations considering power production under normal operation 

throughout a range of wind and wave conditions are considered in the 

1.x-series DLCs. The 2.x-series DLC considers power production with 

fault occurrences, each of which triggers a shutdown of the turbine. The 

6.x- and 7.x-series DLCs consider parked (idling) and idling with fault 

scenarios, respectively, under extreme 1- and 50-year return periods. 

The start-up, normal shutdown, and emergency shutdown events of 

DLCs 3.x, 4.x, and 5.x—as well as the 8.x-series cases that relate to 

transport, assembly, maintenance, and repair—are neglected. In Table 

2, NTM and ETM refer to the normal and extreme turbulence models, 

ECD refers to the extreme coherent gust with direction change, EWS 

refers to extreme wind shear, EOG refers to the extreme operating gust, 

EWM refers to the extreme wind model, and NSS and ESS refer to the 

normal and extreme sea states. The IEC 61400-3 standard explains the 

DLC prescriptions and nomenclature in detail (IEC, 2008). Jonkman 

2007 provides the specifics of how the DLC prescriptions were carried 

out in this project. 

Although the IEC 61400-3 standard explicitly states that “the design 

requirements specified in this standard are not necessarily sufficient to 

ensure the engineering integrity of floating offshore wind turbines”, for 

the purposes of this project (which principally is a conceptual study), 

the stated design requirements were assumed to be sufficient. No 

attempt was made to identify other possible floating platform-specific 

design conditions. 

To account for all of the combinations of wind conditions, wave 

conditions, and control scenarios—together with the number of 

required seeds—2,190 separate time-domain simulations were run for 

each offshore floating wind turbine model, and 452 separate 

simulations were run for the land-based turbine model. Each simulation 

involving a discrete wind event—for DLCs 1.4, 1.5, and 2.3—was 1 

minute long. Each simulation involving an ESS—for DLCs 1.6, 6.x, 

and 7.1a—was 1 hour long. All other simulations—for DLCs 1.1, 1.2, 

1.3, and 2.1—lasted 10 minutes. An additional 30 seconds of 

simulation time (in addition to the times listed) was processed before 

outputting simulation data to eliminate any start-up transient behavior 

that may have otherwise spuriously affected the response predictions. 

For the ultimate-type (U) simulations, extreme-event tables were 

generated for each DLC; these tables then were concatenated to find the 

overall ultimate (maximum) load across all DLCs. Load partial safety 

factors (PSF) were applied in this process to weight each DLC 

properly, as indicated in the last column of Table 2. The IEC 61400-3 

standard requires that the ultimate loads predicted for the RNA in DLC 

1.1 under normal operation with normal wind-turbulence and 

stochastic-wave conditions be based on the statistical extrapolation of 

the load response. To simplify the analysis, we eliminated this 

extrapolation and instead applied an extra factor of 1.2 to all load 

measures in all models. (The factor of 1.2 is based on the authors’ 

experience with loads extrapolation but should be considered as an 

approximation because the extrapolation will—in general—depend on 

the turbine configuration, environmental conditions, and load measure.) 

Furthermore, DLC 1.1 was applied to the loads in both the RNA and 

the floating support structures despite the IEC 61400-3 standard only 

requiring DLC 1.1 to apply to the RNA. 

4 
 

 

 

Table 2. Summary of selected design load cases 

DLC Controls / Events Type Load 

Model Speed Model Height Direction Factor 

1.1 NTM V in < V hub < V out NSS Hs = E[Hs |V hub ] β = 0o Normal operation U 1.25×1.2 

1.2 NTM V in < V hub < V out NSS Hs = E[Hs |V hub ] β = 0o Normal operation F 1.00 

1.3 ETM V in < V hub < V out NSS Hs = E[Hs |V hub ] β = 0o Normal operation U 1.35 

1.4 ECD V hub = V r , V r ±2m/s NSS Hs = E[Hs |V hub ] β = 0o Normal operation; ±∆ wind dir'n. U 1.35 

1.5 EWS V in < V hub < V out NSS Hs = E[Hs |V hub ] β = 0o Normal operation; ±∆ ver. & hor. shr. U 1.35 

1.6a NTM V in < V hub < V out ESS Hs = 1.09×Hs50 β = 0o Normal operation U 1.35 

2.1 NTM V hub = V r , V out NSS Hs = E[Hs |V hub ] β = 0o Pitch runaway → Shutdown U 1.35 

2.3 EOG V hub = V r , V r ±2m/s, V out NSS Hs = E[Hs |V hub ] β = 0o Loss of load → Shutdown U 1.10 

6.1a EWM V hub = 0.95×V 50 ESS Hs = 1.09×Hs50 β = 0o, ±30o Yaw = 0o, ±8o U 1.35 

6.2a EWM V hub = 0.95×V 50 ESS Hs = 1.09×Hs50 β = 0o, ±30o Loss of grid → -180o < Yaw < 180o U 1.10 

6.3a EWM V hub = 0.95×V 1 ESS Hs = 1.09×Hs1 β = 0o, ±30o Yaw = 0o, ±20o U 1.35 

7.1a EWM V hub = 0.95×V 1 ESS Hs = 1.09×Hs1 β = 0o, ±30o Seized blade; Yaw = 0o, ±8o U 1.10 

6) Parked (Idling) 

7) Parked (Idling) and Fault 

Winds Waves 

1) Power Production 

2) Power Production Plus Occurrence of Fault 

For the fatigue-type (F) simulations (DLC 1.2), instead of applying the 

full long-term joint-probability distribution of wind speed, significant 

wave height, and peak-spectral wave period, we assumed that the 

fatigue loads could be reasonably calculated using only the expected 

value of the significant wave height conditioned on mean hub-height 

wind speed, E[Hs,Vhub], together with the median peak spectral period 

associated with each significant wave height. For these fatigue 

simulations, lifetime damage-equivalent loads (DEL) were calculated 

according to the process given in the IEC design standards. This 

process involves (1) binning the cycle ranges and means of each load 

time series by a rainflow-cycle counting (RCC) algorithm, (2) 

transforming the load ranges with varying means to equivalent load 

ranges at a fixed, mean load, (3) extrapolating the short-term cycle 

counts to 20-year lifetime-equivalent cycle counts, and (4) computing 

the lifetime DEL. In this process, the load ranges were transformed 

from varying to fixed mean loads using a Goodman correction with a 

range of assumed ultimate strengths. The ultimate strengths were 

derived by scaling-up the ultimate loads from the land-based loads 

analysis. The extrapolation for the lifetime-equivalent cycle counts 

used a Rayleigh probability distribution for the wind speeds. The 

lifetime DEL was calculated using a range of Wöhler material 

exponents appropriate to each component. Matha 2010 explains the 

fatigue-processing approach of this project in detail, with the 

clarification that the fixed mean load used for scaling was a value of 

zero. 

RESULTS AND DISCUSSION 

the original three floating wind systems. No further details have been 

published for the University of Maine systems. 

To gain insight into the dynamic behavior of the onshore and floating 

systems—and to enable a meaningful comparison between them—the 

results were split into groups which are presented separately here. First, 

the ultimate loads from DLCs 1.1, 1.3, 1.4, and 1.5, which consider the 

wind turbine in normal operation with a variety of external wind and 

wave conditions—not including extreme 1- or 50-year events—are 

presented. Next the fatigue loads from DLC 1.2 are presented. These 

two sets of results embody the response of the systems unencumbered 

by the design problems that will be discussed next. 

Other load cases that were analyzed include DLCs 1.6a, 2.x, 6.x, and 

7.1a, which are concerned with the wind turbine when it is 

experiencing a fault, when it is idling, and when it is being excited by 

1-year and 50-year wind and wave conditions. These load cases 

produced wind turbine loadings that were unacceptably large, and 

therefore were not included in the ultimate load and fatigue analyses. 

Instead, these load cases were used to identify potential problems in the 

system configurations, including the presence of instabilities in all of 

the floating systems. A discussion of these instabilities is provided in 

Jonkman and Matha 2010 for the original three configurations, and will 

not be repeated here. The new University of Maine configurations 

demonstrate the same instabilities as the original concepts, and 

therefore a new discussion is not warranted. 

Ultimate Loads 

Loads analyses for each of the seven system models were run according 

to the specifications, data, and procedures described above. Due to the 

sheer volume of results, only a small fraction can be presented here. 

The results presented focus on the characteristic responses of each 

system and the system-to-system comparisons. Greater detail is 

available in Jonkman 2007 for the land-based NREL 5-MW wind 

turbine and the ITI Energy barge system, and in Matha 2010, and Jason 

and Matha 2010 for the MIT/NREL TLP system and the comparison of 

The absolute extreme loads from the extreme-event tables (the absolute 

maximum values of the minima and maxima) of DLCs 1.1, 1.3, 1.4, 

and 1.5 were calculated. The resulting loads from the six floating wind 

turbine systems were divided by the corresponding absolute extremes 

from the land-based turbine’s analysis. The resulting dimensionless 

ratios quantify the impact of installing an NREL 5-MW wind turbine 

on each of the floating platforms. These ratios are presented in Fig. 2 

for the transverse bending moments of the blade root, of the low-speed 

5 
6 

shaft at the main bearing, of the yaw bearing, and of the tower base. 

(Each transverse bending moment was calculated by taking the vector 

sum of the bending moments about the member’s transverse axes.) 

A ratio of unity implies that the ultimate load is unaffected by the 

dynamic couplings between the turbine and the floating platform in the 

presence of combined wind and wave loading. Ratios greater than unity 

imply an increase in load or response that might have to be addressed 

by modifying the system designs (e.g., strengthening a turbine 

component if the sea-based loads exceed the land-based design 

margins) in subsequent analysis iterations. The comparison shows that 

in general, the floating wind turbines show increased loads on turbine 

components as compared to the land-based system. 

For the land-based wind turbine, many of the greatest loads on the 

blades and shaft were generated by the ECD events of DLC 1.4. The 

extreme turbulence of DLC 1.3—particularly for mean wind speeds 

near rated speed—played a significant role in driving most of the other 

large loads in the system, including the loads in the tower. This is a 

result of a peak in rotor thrust at rated wind speed, which is 

characteristic of a pitch-to-feather-controlled wind turbine. 

0

0.5

1

1.5

2

2.5

Blade-Root

Bending Moment

Low-Speed-Shaft

Bending Moment 

Yaw-Bearing

Bending Moment

Tower-Base

Bending Moment

Ratios of Sea to Land

4.4 MIT/NREL TLP

UMaine TLP

OC3-Hywind

UMaine Hywind

ITI Energy Barge

UMaine Semi

Fig. 2. Sea-to-land ratios of ultimate loads from DLCs 1.1, 1.3, 1.4, and 

1.5 

The wind turbine mounted on the ITI Energy barge was affected more 

by the waves than by the wind. Consequently, DLC 1.1 for the ITI 

Energy barge system—which has the greater effective partial safety 

factor for loads—dominated the load results more than did DLC 1.3, 

which has greater levels of wind turbulence but has the same wave 

conditions. The excessive pitching and rolling motions of the barge 

bring about load excursions in the supported wind turbine that exceed 

those experienced by the turbine installed on land. The load excursions 

become more extreme farther down the load path—from the blade, 

through the drivetrain and nacelle, to the tower—because of the 

increased effect of inertia from the barge-pitch motion. The loads are 

further exacerbated by greater yaw errors between the nominal wind 

direction and the rotor axis in the ITI Energy barge system as compared 

to the land-based system. Greater yaw errors allow for more excitation 

in the side-to-side direction because there is little aerodynamic 

damping. The greater yaw errors are generated by the yaw motion of 

the barge. That motion is excited by a gyroscopic yaw moment 

resulting from the spinning inertia of the rotor in combination with the 

pitching motion of the barge. Greater yaw motions are generated 

because of the yaw compliance of the mooring system. 

The MIT/NREL TLP system has much less platform motion than the 

ITI Energy barge in all modes, but particularly in pitch and roll. The 

ultimate blade and shaft loads in the MIT/NREL TLP system for the 

most part were generated by the same DLC that produced the ultimate 

blade and shaft loads in the land-based wind turbine (DLC 1.4). The 

loads in the MIT/NREL TLP-supported wind turbine are slightly 

greater than those of the land-based turbine due to the limited platform 

motions that do remain. These platform-motion-induced loads cause the 

design-driving load case to change to DLC 1.1 for the MIT/NREL 

TLP-based tower as compared to DLC 1.3 for the land-based tower. 

The UMaine TLP behaves very similarly to the MIT/NREL TLP. The 

ultimate blade and shaft loads were also generated by DLC 1.4, but had 

a slightly lower value than the MIT/NREL TLP, though still larger than 

the land-based system. The decrease in load on the shaft and blades for 

this TLP comes from the fact that it is also surging in the down-wind 

direction during the occurrence of the gust in DLC 1.4, which is what 

generates the extreme load for this case. This surge motion results in a 

decrease in the relative wind speed seen at the blades, thus reducing the 

load. The MIT/NREL TLP also has some surge motion, but it is less at 

the time of the gust, and is in the up-wind direction. This surge motion 

persists even after the system has reached a steady-state, and therefore, 

unless the gust can be applied at the same phase in the surge 

oscillations, the surge motion will alter the effect of the gust between 

the two TLP systems. This difference in initial conditions at the start of 

a transient event is an issue for load case simulations for floating 

offshore systems, and should be addressed during the creation of 

standards specific to floating systems. Another noticeable difference 

between the two TLP systems is in the extreme tower loads at the yawbearing and base. The extreme value of the yaw-bearing moment is 

caused by load case 1.3 for the UMaine TLP, rather than load case 1.4. 

The effect of the wind gust in DLC 1.4 does not produce as large of a 

load increase for the UMaine TLP, due to a combination of the 

differences in the surge and yaw motion of the systems. The UMaine 

TLP has much lower inertia and its mooring system is under less 

tension due to lower excess buoyancy than the MIT/NREL TLP, and 

thus allows for more motion in the yaw direction as well as the other 

platform degrees of freedom, with the exception of pitch. 

The OC3-Hywind spar system has much less pitch and roll motion than 

that of the ITI Energy barge system, but it has much greater pitch and 

roll motions than the TLP systems. In regards to yaw, the OC3-Hywind 

spar system is more stable than the TLPs. This yields generally greater 

loads in the OC3-Hywind system than in the TLP systems, except for 

loads primarily affected by platform yaw. The load increases, however, 

are somewhat compensated by the modifications to the OC3-Hywind 

system’s controller, which trades reduced blade and shaft loading with 

greater power and speed excursions (not shown). These modifications 

actually led to lower turbine loads relative to TLPs in some 

components. The controller, however, was modeled based on the 

platform-pitch frequency of the system in an undisplaced position. 

During rated wind speeds, it was found that the thrust of the rotor 

creates a large offset in the surge direction, which effectively lowers 

the platform-pitch frequency of the system below the designed control 

frequency. This results in a temporary controller-induced instability in 

the platform-pitch mode when the surge displacement is large. For 

future analyses, the frequency of the controller should be lowered to a 

value less than the platform-pitch frequency of any possible operational 

configuration. As compared with the land-based system, DLC 1.4 had 

much less influence on the blades in the OC3-Hywind system due to 

the changes in the turbine control system. Instead, most of the ultimate 

loads in the OC3-Hywind system were driven by DLC 1.3. 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The UMaine-Hywind system, which models the spar buoy at a depth of 

200 m, is very similar to the OC3 version, which is at a depth of 320 m. 

The only significant difference between the systems is the extreme load 

for the low speed shaft, which increases slightly in the UMaine system. 

The extreme load in the low speed shaft occurs for both spar systems in 

the same high turbulence event (from DLC 1.3) when there is a sudden 

increase in the wind speed in conjunction with a decrease in the amount 

of wind shear across the rotor. The magnitude of this load is tied to the 

pitching and surge motion of the system, and is not significant for the 

TLP, semisubmersible, or land-based systems. The reason the load is 

higher for the spar in shallower water is not fully understood, but is 

related to the degree to which the system is pitched during the dynamic 

shear event. 

The motion of the UMaine semisubmersible system (semi) is most 

similar to the motion of the spar systems, with the exception of its 

heave motion, which is much larger, and its pitch motion, which is 

smaller. The sensitivity of the system in the heave direction can be seen 

by the dominance of high-period wave simulations as the designdriving load cases, especially for the low speed shaft and yaw bearing 

moments. The heave period for the system is approximately 17 

seconds, with peak periods of the wave spectra topping out at 18.3 

seconds. The increased heave motion of the system as compared to the 

spar results in a slight increase in the ultimate loads seen throughout the 

system due to increased inertial loading, with the exception of the 

tower-base bending moment. The tower-bending moment is largely 

influenced by the pitching motion of the system, which is smaller for 

the semi than the spars, and outweighs the effects of the heave motion. 

The largest increase in the ultimate load due to the heave motion of the 

semi can be seen in the yaw-bearing moment. The design load cases 

which cause the highest loads in the semi are also very similar to the 

spar, with the extreme turbulence of DLC 1.3 dominating. 

Fatigue Loads 

Fig. 3 presents the ratios calculated by dividing the lifetime DELs for 

the six investigated floating wind turbine concepts by the 

corresponding lifetime DELs from the land-based analysis. Ratios are 

given for the in-plane and out-of-plane blade-root bending moments, 

the 0° and 90° low-speed-shaft bending moments at the main bearing, 

and the side-to-side and fore-aft bending moments in the yaw bearing 

and in the tower base. Each DEL is computed using multiple Wöhler 

material exponents (m). For the composite blade, the DELs are 

computed using m equal to 8, 10, and 12. For the steel shaft and tower, 

the DELs are computed using m equal to 3, 4, and 5. Although the 

DELs also were calculated using a range of ultimate strengths, Fig. 3 

presents only the results calculated with the greatest ultimate strengths 

applied. (The DELs asymptotically approach a constant value as the 

ultimate strength is increased; see Matha 2010). 

In general, the fatigue load ratios show similar trends to those of the 

ultimate load ratios, and are produced by the same physics explained 

for the ultimate loads. The fatigue loads of the ITI Energy bargesupported wind turbine are by far the greatest for all of the concepts— 

particularly for the blade and tower. The out-of-plane blade-root 

bending fatigue loads in the spar systems and semi are, perhaps 

surprisingly, less than those of the land-based system. This is a result of 

the controller modification in the semi and spar systems, which—as 

stated above—trades reduced blade and shaft loading for greater power 

and speed excursions. The differences in the fatigue loads between the 

TLP systems and the semi and spar systems are not significant, except 

for the fatigue loads of the tower base, which are greater in the semi 

and spar systems due to their increased motion in roll and pitch. The 

pitch motion of the semi is less than that of the spar, and so the fatigue 

at the tower-base in the fore-aft direction is less as well as the bladeroot out-of-plane bending moment. The fatigue loads for the UMaine 

TLP system in general increase slightly compared to the NREL/MIT 

TLP system due to the increased platform motion, with the exception of 

pitch. The exception is the out-of-plane blade-root bending moment 

and the fore-aft tower bending moment, which are both influenced by 

the pitching motion of the system. The increased stiffness of the 

mooring lines of the UMaine TLP decreases the pitch motion in the 

system, which results in decreased fatigue loads associated with the 

pitching motion. 

CONCLUSIONS 

The results presented in this work characterize the dynamic responses 

of six different floating wind turbine concepts, represented here by the 

MIT/NREL TLP, the UMaine TLP, the OC3-Hywind spar buoy, the 

UMaine-Hywind spar buoy, the ITI Energy barge system, and the 

UMaine semisubmersible, together with the NREL 5-MW baseline 

wind turbine. The impacts brought about by the dynamic coupling 

between the turbine and each floating platform are presented, and 

comparisons between the concepts are quantified. In summary, all of 

the floating wind turbines show increased loads on turbine components 

as compared to the land-based system, and therefore must be 

strengthened. The platform motion-induced ultimate and fatigue loads 

for all turbine components in the ITI Energy barge are the highest 

found for these six concepts. The designs for the two TLP systems were 

very different, but it was found that their response was fairly similar. 

This shows that the method for stabilizing the floating system is more 

influential on the dynamics of the system than the details of the design. 

The differences in the ultimate and fatigue loads between the TLP 

systems and the spar and semi systems are not significant, except for 

the loads in the tower, which are less for the TLP systems. The 

modeling of the OC3-Hywind system at a shallower depth did not have 

a significant effect on the system dynamics. 

One issue discovered during these simulations is the effect of platform 

motion in the floating systems on the resulting extreme loads. New 

standards with load cases specifically designed for floating systems are 

now being created. This issue should be addressed when developing 

the appropriate load case scenarios. For instance, the extreme load 

from a transient event could be assessed by simulating the transient 

event at a variety of onset times. This would address the influence of 

the alignment of the transient event with a specific phase of the 

platform motion. 

These results will help resolve the fundamental design trade-offs 

between the floating system concepts. Although the present results 

quantify the extent by which the choices in platform configuration 

impact the turbine loads and ultimately the turbine design, without 

further considerations (especially economic), no definite statement can 

yet be made about which concept or hybrid thereof is likely the “best.” 

Therefore, future work will be focused on cost modeling, model 

improvement, and the analysis of other floating wind turbine concepts. 

To improve the UMaine models, data from the scaled model tests of 

these concepts will be examined. This data will be used to validate the 

UMaine models, and better understand the limitations of the simulation 

tools being used. 

ACKNOWLEDGEMENTS 

This work was performed at NREL in support of the U.S. Department 

of Energy Wind and Water Power Program. 

7 
8 

REFERENCES 

IEC (2008). IEC 61400–3 Ed. 1. Wind Turbines – Part 3: Design 

Requirements for Offshore Wind Turbines. 

Jonkman, JM, and Buhl, ML Jr. (2005). FAST User’s Guide. 

NREL/EL-500-38230 (previously NREL/EL-500-29798). NREL: 

Golden, CO. 

Jonkman, JM (2007). Dynamics Modeling and Loads Analysis of an 

Offshore Floating Wind Turbine. PhD Thesis, Department of 

Aerospace Engineering Sciences, University of Colorado, 

Boulder, CO, 2007. [Online]. Available: 

http://www.nrel.gov/docs/fy08osti/41958.pdf (Accessed 26 May 

2010) 

Jonkman, JM (2009a). “Dynamics of Offshore Floating Wind 

Turbines—Model Development and Verification,” Wind Energy,

Vol 12, pp 459-492. 

Jonkman, BJ, and Buhl, ML Jr. (2009b). TurbSim User’s Guide, 

NREL/EL-500-46198 (previously NREL/EL-500-41136). NREL: 

Golden, CO, 2009. 

Jonkman, J, Butterfield, S, Musial, W, and Scott, G (2009c). Definition 

of a 5-MW Reference Wind Turbine for Offshore System 

Development. NREL/TP-500-38060. NREL: Golden, CO. 

Jonkman, J (2009d). Definition of the Floating System for Phase IV of 

OC3. NREL/TP-500-47535. NREL: Golden, CO. 

Jonkman, JM, and Matha, D (2010). “Dynamics of offshore floating 

wind turbines – analysis of three concepts,” Wind Energy, 

Accepted and Printing Pending, DOI: 10.1002/we.442; NREL/JA500-48495. Golden, CO: National Renewable Energy Laboratory. 

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Dynamics Aerodynamics Computer Software AeroDyn. Windward 

Engineering LLC: Salt Lake City, UT, 2002. 

Larsen, TJ, and Hanson, TD (2007). “A Method to Avoid Negative 

Damped Low Frequent Tower Vibrations for a Floating, Pitch 

Controlled Wind Turbine,” Journal of Physics: Conference Series, 

The Second Conference on The Science of Making Torque From 

Wind, Copenhagen, pp 28–31 August 2007; DOI:10.1088/1742-

6596/75/1/012073. 

Lee, CH, and Newman, JN (2006). WAMIT User Manual, Versions 6.3, 

6.3PC, 6.3S, 6.3S-PC. WAMIT, Inc.: Chestnut Hill, MA. 

Matha, D (2010). Model Development and Loads Analysis of an 

Offshore Wind Turbine on a Tension Leg Platform, with a 

Comparison to Other Floating Turbine Concepts. MS Thesis, 

Endowed Chair of Wind Energy, Universität Stuttgart, Germany, 

2009. [Online]. Available: http://www.nrel.gov/docs/fy10osti/ 

45891.pdf (Accessed 26 May 2010) 

0

0.5

1

1.5

2

2.5

3

Ratios of Sea to Land

Blade-Root

Bending Moment

In-Plane

 Blade-Root 

Bending Moment

 Out-of-Plane 

Low-Speed-Shaft

Bending Moment 

 0o 

Low-Speed-Shaft

Bending Moment 

 90o 

 Yaw-Bearing 

Bending Moment

 Side-to-Side 

 Yaw-Bearing 

Bending Moment

 Fore-Aft 

 Tower-Base 

Bending Moment

 Side-to-Side 

 Tower-Base 

Bending Moment

 Fore-Aft 

4-5 8-9

m=8/3, MIT/NREL TLP

m=10/4, MIT/NREL TLP

m=12/5, MIT/NREL TLP

m=8/3, UMaine TLP

m=10/4, UMaine TLP

m=12/5, UMaine TLP

m=8/3, OC3-Hywind

m=10/4, OC3-Hywind

m=12/5, OC3-Hywind

m=8/3, UMaine Hywind

m=10/4, UMaine Hywind

m=12/5, UMaine Hywind

m=8/3, ITI Energy Barge

m=10/4, ITI Energy Barge

m=12/5, ITI Energy Barge

m=8/3, UMaine Semi

m=10/4, UMaine Semi

m=12/5, UMaine Semi

Fig. 3. Sea-to-land ratios of fatigue loads from DLC 1.2