DNVGL-RP-0142 Wellhead fatigue analysis · PDF fileRecommended practice DNVGL-RP-0142 – Edition April 2015 Page 9 ... Specification for Marine Drilling Riser Couplings — API RP

RECOMMENDED PRACTICE
DNVGL-RP-0142 Edition April 2015
Wellhead fatigue analysis

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The electronic pdf version of this document found through http://www.dnvgl.com is the officially binding version. The documents are available free of charge in PDF format.

FOREWORD
DNV GL recommended practices contain sound engineering practice and guidance.
© DNV GL AS April 2015

Any comments may be sent by e-mail to [email protected]

This service document has been prepared based on available knowledge, technology and/or information at the time of issuance of this document. The use of thisdocument by others than DNV GL is at the user's sole risk. DNV GL does not accept any liability or responsibility for loss or damages resulting from any use ofthis document.

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GeneralThis is a new document.

Acknowledgements:The following are participants in the Structural Well Integrity joint industry project (JIP):

In addition to the participants mentioned above, Stress Engineering Services Inc. has contributed to the development of this RP.

BP Centrica Chevron Det Norske Eni ExxonMobil GDF Suez Hess Lundin Marathon Nexen Shell Statoil Talisman Total Woodside

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CONTENTS
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Sec.1 General ......................................................................................................... 61.1 Introduction ...........................................................................................61.2 Extended disclaimer ...............................................................................61.3 Background ...........................................................................................61.4 Objective................................................................................................61.5 Scope and applicability...........................................................................81.6 Structure of this document.....................................................................91.7 Limitations ............................................................................................91.8 Informative references...........................................................................9

Sec.2 Definitions and abbreviations...................................................................... 102.1 Definitions............................................................................................102.2 Abbreviations .......................................................................................12

Sec.3 Operational and system description ............................................................ 143.1 Introduction ........................................................................................143.2 Types of operations .............................................................................14

3.2.1 Drilling ......................................................................................143.2.2 Completion .................................................................................153.2.3 Production ..................................................................................153.2.4 Workover....................................................................................153.2.5 Plug and abandonment .................................................................15

3.3 System description ..............................................................................163.3.1 Rig ............................................................................................163.3.2 System configuration/stack-up ......................................................163.3.3 Tensioning/compensation systems .................................................233.3.4 Additional surface equipment.........................................................233.3.5 Upper packages ...........................................................................233.3.6 Riser joints/components ...............................................................243.3.7 Flex joints...................................................................................243.3.8 Lower packages ...........................................................................243.3.9 Wellhead system..........................................................................243.3.10 Casing system.............................................................................253.3.11 Subsea template structure ............................................................25

3.4 Site-specific details ............................................................................253.4.1 Operational data requirements.......................................................253.4.2 Soil properties .............................................................................253.4.3 Environmental conditions ..............................................................25

Sec.4 System modeling and response................................................................... 274.1 Introduction .........................................................................................274.2 General considerations.........................................................................33

4.2.1 Selection of assumptions...............................................................334.2.2 Mean loads .................................................................................334.2.3 Soil properties .............................................................................334.2.4 Cement level ...............................................................................344.2.5 Non-linear effects ........................................................................344.2.6 Special-purpose simulations ..........................................................344.2.7 Representation of outputs .............................................................34


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4.3 Global analysis model...........................................................................35
4.3.1 Purpose ......................................................................................354.3.2 Analysis type...............................................................................354.3.3 Modelling considerations – rig .......................................................354.3.4 Modelling considerations – riser system .........................................364.3.5 Modelling considerations – environmental conditions and operating

parameters .................................................................................394.3.6 Typical outputs ............................................................................40

4.4 Local analysis model(s)........................................................................414.4.1 Purpose ......................................................................................414.4.2 System analysis...........................................................................414.4.3 Detailed analysis..........................................................................424.4.4 Testing .......................................................................................43

4.5 Damage model .....................................................................................434.5.1 Fatigue assessment using S-N-curves .............................................434.5.2 Fracture mechanics .....................................................................434.5.3 Initiation life method ....................................................................44

4.6 Fatigue calculation ...............................................................................44App. A Tabular listings of inputs needed for wellhead fatigue analysis .................. 46App. B Flowcharts describing examples of wellhead fatigue analysis methods ...... 60


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SECTION 1 GENERAL
1.1 IntroductionDNVGL-RP-0142 Wellhead fatigue analysis has been developed based on the ongoing Structural Well Integrity Joint Industry Project (JIP). Phase 1 of the JIP was initiated in 2010 and continued into phase 2. The content of this document is primarily based on input from the participants and the service provider Stress Engineering Services Inc., as well as contributions from DNV GL.

The RP was developed in regular project meetings and workshops involving individuals from the participants, DNV GL and external service providers. In case consensus has not been achievable, DNV GL has sought to provide acceptable compromises.

1.2 Extended disclaimerIn addition to the standard liability disclaimer shown in the footer on page 2, the disclaimer for this RP is extended as follows:

DNV GL and participants do not accept any liability or responsibility for loss or damages resulting from any use of this document.

DNV GL holds all rights to this recommended practice, including copyright.

1.3 Background Over recent decades, the complexity and duration of offshore drilling activities has steadily increased. Additionally, equipment sizes like subsea BOP stack have grown significantly. These factors have led to an increase of fatigue loads experienced by the wellhead/casing system.

Fatigue is the progressive and localized structural damage that occurs when a material is subjected to cyclic loading. Fatigue damage is generally characterized as having two phases: (a) crack initiation and (b) subsequent crack propagation, which may lead to unstable fracture.

Analysis of a connected riser system including the well system is both complex and multidisciplinary. As schematically illustrated in Figure 1-1, a connected system consists of several interacting components extending from the rig, through the riser system including any lower package, such as subsea stack and/or subsea tree, and to the wellhead/casing system, which then interacts with the surrounding soil. The combination of rig and riser may change during various stages of operations on the well, such as drilling, completion, workover, production and P&A. Examples of possible system configurations are given in [3.3.2].

During all riser-connected operations, the well system is subjected to fatigue loading induced by environmental conditions, like waves, current, wind, and associated rig motions. Interactions between the rig, riser system, wellhead system e.g., high and low pressure housings, casing system and soils should be adequately modelled to assess the fatigue life of equipment above and below the mudline.

Severity of the fatigue loading depends on the environmental conditions and associated rig motions during a particular operation. Fatigue damage rate may be highest for certain operations, depending on the system configuration, such as drilling riser with subsea stack, and operating parameters. Moreover, some operations like P&A, may involve use of multiple stack-ups, which causes fatigue damage rate to vary.

1.4 ObjectiveIndustry has identified that analyses to assess structural integrity of wellhead/casing systems need to use an aligned methodology to further improve the accuracy, consistency, and repeatability of results. This document provides a consolidated framework for assessing fatigue of wellhead/casing systems due to wave-induced loading. Other sources of fatigue damage which may be important are not addressed.

This RP does not prescribe nor mandate any specific analysis methodology or set of assumptions for wellhead fatigue analysis, but rather discusses the following aspects:

— required inputs — overview of methodologies


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— pertinent modelling details to consider.
Selection of analysis methodologies and assumptions should be based on system details, project stage, and available data.

As part of the JIP several technical reports (TR) will be developed. These technical reports will address topics, among others, such as:

— vessel RAOs— damping sources— dynamic stiffness, hysteretic damping— hydrodynamic properties— soil modelling— coupling vs decoupling— TD and FD analyses procedures — lower flex joint modelling details— SCF and SAF— VIV loads and calculation methods — other modelling considerations.

Moreover, it is the intent to update this RP based on findings from ongoing tasks in the JIP and from other relevant sources over time.

The RP does not stipulate any specific acceptance criteria, as these are considered to be covered by relevant regulatory requirements and responsible stakeholder policies.

This RP is not a substitute for sound engineering judgment by qualified engineers as required for each individual application.


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Figure 1-1 Schematic for example of connected system

1.5 Scope and applicabilityThe scope of this RP addresses the full lifecycle of any offshore well system. The assessment of wellhead fatigue damage under this RP is applicable during all stages or types of operations when riser systems interface to the well, including drilling, completion, production, workover, and P&A. Fatigue accumulation continues until the riser is ultimately disconnected from the wellhead.

This document provides a consolidated framework for fatigue assessment of subsea and surface well systems by considering the following:

— computation of both mean and cyclic loads experienced by the wellhead/casing system for each set of conditions

— relationship between cyclic loads and cyclic stresses, e.g., load-to-stress curves, stress amplification/concentration factors, etc., for each location of interest

— damage model, e.g., S-N approach, initiation life method, fracture mechanics, etc., used to estimate fatigue damage at each location of interest.

Example locations of interest within the well system are listed in [4.1].

This document discusses several existing analysis methodologies and common assumptions typically used for the global model, local model(s), damage model, and fatigue calculations; however, a specific analysis methodology or set of assumptions is not prescribed. Moreover, different analysis approaches and differing levels of detail can be chosen, depending on the stage of the project, e.g., preliminary design, detailed design, hindcasting/forecasting, etc., and availability of required inputs.


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1.6 Structure of this document
Sec.3 focuses on inputs needed to perform wellhead fatigue analysis. [3.2] provides a brief discussion of all relevant operations, as well as examples of system configurations for combinations of rig and riser ([3.3.2]). Listings in tabular format of inputs required to describe the connected system ([3.3.1] and [3.3.3] to [3.3.10]) and site-specific details ([3.4]) are given.

Sec.4 discusses important topics related to performing analyses and estimating fatigue damage. Several general considerations, applicable to both global and local analysis models, are discussed in [4.2]. Important considerations and typical outputs for the global and local analysis models are given in [4.3] and [4.4], respectively. Lastly, [4.5] and [4.6] provide guidance regarding damage models and fatigue calculations, respectively.

1.7 Limitations The RP is limited to fatigue analysis of wellhead/casing systems under wave loadings (and associated rig motions) only. A similar approach could be applied to calculate wellhead/casing fatigue due to VIV-induced riser motions; however, the RP does not address prediction of VIV loading.

This RP does not address other sources of fatigue damage to the well system e.g., VIM, flow-induced vibration, temperature/pressure cycles, bottom currents, pile-driving during conductor installation, etc. which may require additional consideration.

Guidance provided in this document reflects the best industry practice at the time of publication.

1.8 Informative referencesThe following documents, in whole or in part, are informative referenced in this document, and the latest edition of the referenced document (including any amendments) applies.

— API RP 2A-LRFD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms – Load and Resistance Factor Design

— API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms – Working Stress Design

— API Std 2RD, Dynamic Risers for Floating Production Systems

— API Spec 16F, Specification for Marine Drilling Riser Equipment

— API RP 16Q, Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems

— API Spec 16R, Specification for Marine Drilling Riser Couplings

— API RP 579-1/ASME FFS-1, Fitness for Service

— BS 7910, Guide to methods for assessing the acceptability of flaws in metallic structures

— DNV-OS-F201, Dynamic Risers

— DNVGL-RP-0005, RP-C203: Fatigue design of offshore steel structures

— DNV-RP-C205, Environmental Conditions and Environmental Loads

— ISO 13624-1, Petroleum and Natural Gas Industries-Drilling and Production Equipment, Design and operation of marine drilling riser equipment

— ISO/TR 13624-2, Petroleum and Natural Gas Industries-Drilling and Production Equipment, Part 2: Deepwater drilling riser methodologies, operation, and integrity technical report

— ISO 13628-7, Petroleum and Natural Gas Industries – Design and Operation of Subsea Production Systems – Part 7: Completion and Workover Riser Systems

— ISO 19902:2007(E), Petroleum and natural gas industries — Fixed steel offshore structures


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SECTION 2 DEFINITIONS AND ABBREVIATIONS
2.1 DefinitionsTerm Definitionadditional surface equipment

Used in this document to refer to any equipment located above any upper package and installed within the rig’s derrick to facilitate completion/workover operations. This equipment typically consists of a lift frame and the stack-up of components inside it.

blowout preventer Equipment installed on the wellhead system to contain wellbore fluids either in the annular space between the casing and the tubulars or in an open hole during well drilling, completion, and testing operations.

blowout preventer stack (or BOP stack)

See lower stack.

casing system The system consisting of the conductor casing, the surface casing, intermediate casing strings, as well as their associated welds/connectors and cement.

compensation system See tensioning system.component A constituent part or element of a system, which can be considered as an individual item for

the calculation.conductor casing The casing string that is initially installed and is the main structural component of the well.

It is also sometimes referred to as structural casing or drive pipe. connected system Used in the document to refer to all equipment extending from the rig, through the riser

system, and to the well system, which then interacts with the surrounding soil. This also includes any additional surface equipment, tensioning/compensation system, and other constraints back to the rig.

connector Mechanical device used to connect adjacent components in the connected system to create a structural joint resisting applied loads and preventing leakage.

coupled motions model Model for determining rig motions that includes a discrete representation of the floating vessel and any mooring lines (and/or installed risers).

detailed analysis Analysis performed to determine the local stress distribution at locations of interest.detailed model Analysis model containing all significant geometric features without simplification, including

all features used to calculate SAF/SCF. In some instances, the detailed model may be incorporated into the local model.

dynamic positioning (or automatic station-keeping)

Computerized means of maintaining a floating vessel on location by selectively driving thrusters.

emergency disconnect package (or EDP)

Upper section of an LWRP that allows for quick disconnect of the riser system from the subsea wellhead. This interfaces with the lower section of the LWRP.

fatigue damage rate Expression for the accumulation of fatigue damage as a function of time in units of time-1.flex joint (or ball joint) Device installed along the riser system to permit relative angular movement of the riser and

reduce stresses due to rig motions and environmental forces.fracture toughness Material property which describes the ability of a material containing a crack to resist

fracture, i.e., an indication of the amount of stress required to propagate a pre-existing flaw.fully-integrated model Analysis model consisting of the global model and local model (system and detailed models)

without any de-coupling of the rig.global analysis Analysis to determine loads imposed on the well system by the riser system due to

environmental loading and associated rig motions.global model Model of the connected system for the purpose of global analysis, which may incorporate

the local model or be separate from it.heat-affected zone Region around a weld that has been affected by welding.initiation life Damage model used to estimate fatigue damage using the local strain approach.intermediate casing strings

Casing strings that may be installed in addition to the conductor and surface casing strings, depending on the well design.

load Physical influence which causes stress and/or strains in the connected system.load case Combination of loads acting simultaneously.load to stress relationship (also stress load ratio)

Ratio of the incremental change of peak surface stress to the corresponding incremental change in the global load (tension, bending, or shear), sometimes referred to as the stress load ratio.


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local analysis Analysis of the well system for the purpose of determining load transfer among components and local stress distributions.

local model Model of the well system for the purpose of local analysis. It may be incorporated into the global model or separate from it. Moreover, the local model may incorporate the detailed model.

low frequency motions Motion response of a floating vessel at frequencies below wave frequencies and typically with periods ranging from 30 to 300 seconds.

lower marine riser package (or LMRP)

Upper section of a subsea stack consisting of a hydraulic connector, annular BOP, flex/ball joint, riser adapter, jumper lines for the choke, kill, and auxiliary lines, and the subsea control pods. This interfaces with the lower section of the subsea stack.

lower package Used in the document to refer to any collection of large equipment located between a subsea wellhead system and the bottommost riser joint/component.

lower riser package (or LRP)

Lower section of an LWRP, including a hydraulic connector, that typically connects to the wellhead system, subsea tree, tubing head spool, and EDP.

lower stack Lower section of a subsea stack that contains blow-out preventers, spools, valves, hydraulic connectors, and nipples that typically connect to the wellhead system, subsea tree, tubing head spool, and LMRP.

lower workover riser package (or LWRP)

Complete assembly of well control equipment for safe operating status during completion/workover operations to the well. The LWRP consists of the EDP and the LRP.

mean vessel offset Offset of the rig created by steady forces from current, wind, and waves and controlled by station-keeping capabilities.

peak surface stress Highest stress in the region or component under consideration. The basic characteristic of a peak surface stress is that is causes no significant distortion and is principally objectionable as a possible initiation site for a fatigue crack. These stresses are highly localized and occur at geometric discontinuities or transitions.

pre-load Internal load independent of any working load accomplished by elastic deformation during installation.

response amplitude operator (or RAO)

Relationship between the wave surface elevation amplitude at a reference location and the vessel response amplitude, and the phase lag between the two.

rig Used in this document to refer to any floating vessel or structure from which the riser system is deployed.

riser joint Joint consisting of a tubular member(s) with riser connectors at the ends.riser system Used in the document to refer to any deployed assembly of lower package(s), riser joints/

components, and upper package(s). rotary Kelly bushing (or RKB)

Vertical reference to drillfloor.

stress amplification factor Local slope of the peak surface stress versus reference stress curve i.e., the ratio of the incremental change of local peak stress to the corresponding incremental change of the reference stress.

stress concentration factor

Used in this document to mean the geometric stress concentration factor, i.e., ratio of the peak surface stress in a component or feature to the nominal stress.

stress load ratio See load to stress relationship.structural casing See conductor casing.sub blocking Reduction of the number of weather bins representing a wave scatter diagram.subsea stack Complete assembly of well control equipment, including BOPs, spools, valves, and nipples.

The subsea stack of a drilling riser consists of the LMRP and the lower stack.subsea template structure

Structure that supports other equipment such as manifolds, risers, drilling and completion equipment. The template may be used as a guiding system during conductor installation.

subsea tree Assembly of valves attached to the top of the subsea wellhead to direct and control the flow of formation fluids from the well.

surface casing Large-diameter, relatively low-pressure pipe string set and cemented in shallow yet competent formations for several reasons e.g., the surface casing provides pressure integrity and structural strength so that the remaining casing strings may be suspended at the top and inside of the surface casing.

surface flowhead Device placed at top of the riser to direct and control the flow of fluids from the well and/or annulus bores during completion, early production, or workover.

surface tree Device placed at top of the riser to direct and control the flow of formation fluids from the well and/or annulus bores during production.

Term Definition


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2.2 Abbreviations

tensioning system (or riser tensioner)

Device that applies a tension to the riser system while compensating for the relative vertical motion (stroke) between the floating rig and the top of the deployed riser system.

upper package Used in the document to refer to any collection of well control equipment located above the topmost riser joint/component.

vortex-induced vibration (or VIV)

In-line and transverse oscillation of a riser in a current induced by the periodic shedding of vortices.

well system Consists of the wellhead system and casing system.wellhead system System consisting of the high and low pressure wellhead housings, lock-down or pre-load

mechanisms, intermediate casing hangers, housing extensions, welds, and secondary appurtenances.

Abbreviation Description2D two-dimensional3D three-dimensionalAHD active heave drawworksAPI American Petroleum InstituteASTM American Society of Testing and MaterialsBOP blowout preventerBS British StandardCa added mass coefficientCd drag coefficientCFD computational fluid dynamicsCm inertia coefficientCMC crown-mounted compensatorCT coiled tubingCWO completion/workoverCWOR completion/workover riserDP dynamic posistioningECA engineering criticality assessmentEDP emergency disconnect packageFAD failure assessment diagramFD frequency-domainFPSO floating production, storage and offloading unitFPU floating production unitGA general assemblyHAZ heat affected zoneHPH high pressure housingHs significant wave heightID inner diameterIFJ intermediate flex jointISO International Organization for StandardizationJIP joint industry projectKC Keulegan-CarpenterLFJ lower flex jointLMRP lower marine riser packageLPH low pressure housingLRP lower riser packageLWRP lower workover riser packageM-N moment to number of cyclesMODU mobile offshore drilling unit

Term Definition


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NDT non-destructive testingOD outer diameterP&A plug and abandonmentP-Y lateral soil load-deflectionPWHT post-weld heat treatmentRAO response amplitude operatorRe Reynolds numberRMS root mean squareRP recommended practiceS-N stress to number of cyclesSAF stress amplification factorSCF stress concentration factorSID subsea isolation deviceSMYS specified minimum yield strengthSSTT subsea test treeT-Z axial load transferTD time-domainTH tubing hangerTLP tensioned leg platformTp peak wave periodTR technical report, in the context of this RP produced by the JIPTTR top-tensioned riserTz zero up-crossing periodUFJ upper flex jointVIM vortex-induced motions of platformVIV vortex-induced vibrationXT subsea tree = Christmas tree (oil well) = xmas treeYr year

Abbreviation Description


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SECTION 3 OPERATIONAL AND SYSTEM DESCRIPTION
3.1 Introduction Fatigue loading on the wellhead/casing system is governed by the operation performed and the system configuration, examples of which are shown in [3.3.2]. This section discusses inputs required to describe each operation and system for the purpose of creating a representative model(s) as part of wellhead fatigue analysis. Listings of inputs required to describe the connected system e.g., rig, riser system, wellhead/casing system, etc. and site-specific details e.g., operational data, soil properties, and environmental conditions are provided.

3.2 Types of operations

3.2.1 Drilling Drilling is performed using a MODU or a FPU. Drilling operations begin in open water and continue through a riser. Figure 3-1 contains a schematic showing a simplified example of a well construction sequence, specifically though a drilling riser operated from a MODU.

Well construction starts by first spudding the well in open water with the conductor casing, which may involve use of a template and/or other reinforcing structures. The conductor casing is set to a sufficient depth below the mudline to support the weight of the wellhead, subsea stack and internal casing strings. The conductor casing may be installed by jetting, driving, or by drilling and cementing.

After the conductor casing with low pressure housing (LPH) is installed, drilling continues and the surface casing with high pressure housing (HPH) is installed and cemented. In some instances, open water operations may include additional casing between the conductor casing and the surface casing. Cementing level/quality can have a significant impact on the fatigue response of the wellhead/casing system.

After cementing of the surface casing with HPH, the riser and drilling equipment are then connected to the HPH. From this stage onwards, fatigue loading is transmitted to the wellhead/casing system for the remainder of the drilling operations until the lower package is disconnected.


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Figure 3-1 Example of well construction sequence (using drilling riser operated from MODU)

3.2.2 CompletionCompletion usually begins with the running and installation of the production casing and may employ either vertical or horizontal XTs and associated spools. This increases the height and weight of the lower package, which can influence fatigue damage accumulated by the wellhead/casing system. During completion, the wellbore may be accessed using a completion/workover riser (XT-mode) or through a drilling/production riser (TH-mode).

3.2.3 ProductionProduction systems include dry tree or wet tree configurations. For dry (or surface) tree systems using top-tensioned production risers (TTRs), wellhead fatigue damage during the life of field may be significant as the riser is connected permanently to the subsea and surface wellheads.

Wet (or subsea) tree systems include a subsea tree (XT) connected to the HPH and attach to subsea production systems via manifolds, jumpers, and flowlines.

3.2.4 WorkoverWorkover operations can vary in duration and complexity and may include sidetracks, re-completions, or other interventions. Workovers may be performed using a completion/workover riser (XT-mode) or through a drilling/production riser (TH-mode). Additional surface equipment associated with workover operations e.g., wireline or coiled tubing operations) can affect the system dynamics and may be considered.

3.2.5 Plug and abandonmentPlug and abandonment (P&A) operations involve pulling equipment e.g. tree, tubing, etc.), setting a number of zonal isolation cement plugs, and may involve removing portions of the wellhead/casing system. These operations may take several weeks depending on the complexity of the well system, thus the potential for fatigue damage should be considered during well design.


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3.3 System description
The connected system consists of the wellhead/casing system, a riser system, the tensioning/compensation system(s) and any additional surface equipment. Depending on the rig and operation, a riser system includes any of the following items (starting at top): upper package, riser joints/components (including any flex joints), and lower package, which are further discussed in [3.3.5] to [3.3.8].

Rig motions, tension variations, and environmental loads (experienced by the riser system) induce cyclic loads to the wellhead/casing system. For this reason, a complete and accurate description of the rig and connected system is required for wellhead fatigue analysis.

3.3.1 Rig The two most common categories of rigs are MODUs e.g., jack-up, semisubmersible and drillship) and FPUs e.g., semisubmersible, spar, TLP, FPSO, etc. Note that the rig typically changes for various operations e.g., drilling, completion, production, intervention, workover, etc. The rig interacts with the riser system through the tensioning/compensation system(s), and the rig may impose other constraints e.g., centralizers, moonpool, keel, etc. to the riser system. Rig motions, in response to the environment, can have a large influence on dynamic loads experienced by the wellhead/casing system.

For floating rigs, station-keeping is accomplished through use of a mooring system or a dynamic positioning (DP) system. In some instances, station-keeping of moored rigs is enhanced by thruster assist. Rig motions are characterized by mean vessel offset, wave frequency motions, and low-frequency motions.

Wave frequency motions of floating rigs are usually characterized by response amplitude operators (RAOs), which define both the magnitude and phasing of vessel responses to the wave over a range of periods. Note the range and spacing of wave periods (for which RAOs are given) should be sufficient to capture all rig motions for the sea states to be evaluated.

For DP rigs, the tolerance of the mean offset may be provided. If operations are performed from a moored rig, mean/maximum offsets and low frequency motions (when thruster assist is not used) may be considered for all environments.

Table A-1 lists the information required to describe the rig e.g., vessel RAOs, GA drawings, etc.

As an alternative to vessel RAOs, rig motions can be applied directly to the riser through the use of a coupled motions model, which includes a representation of the rig and any mooring lines (and/or installed risers) attached to it.

If operations are performed from a jack-up or jack-up over jacket, rig response to wave loading should be considered.

3.3.2 System configuration/stack-upThe system configuration/stack-up is required in developing global analysis models. System configurations may be different for each operation, rig, and riser. Examples of system configuration may include those listed below:

Use of Subsea Wellhead System only

— Drilling riser operated from a MODU – see Figure 3-2— Completion/workover riser operated from a MODU – see Figure 3-3

Use of Surface Wellhead System only

— Riser for drilling/production operations from a jack-up – see Figure 3-4

Use of both Subsea and Surface Wellhead Systems

— Riser for drilling/production operations from a spar (FPU) – see Figure 3-5— Riser for drilling/production operations from a TLP (FPU) – see Figure 3-6— High pressure riser from a jack-up – see Figure 3-7

The actual configuration for each operation should be evaluated.


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Table A-2 lists examples of details to be provided for each system configuration (listed in typical order
beginning at top), several of which are discussed further in sections below.

Figure 3-2 Example of a drilling riser operated from a MODU


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Figure 3-3 Example of completion/workover riser operated from a MODU


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Figure 3-4 Example of riser for drilling/production operations from a jack-up


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Figure 3-5 Example of riser for drilling/production operations from a Spar


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Figure 3-6 Example of riser for drilling/production operations from a TLP


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Figure 3-7 Example of high-pressure riser operated from a jack-up


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3.3.3 Tensioning/compensation systems
Connected systems are supported through tension supplied by a tensioning system or a compensation system, both of which provide heave compensation. Tensioning systems primarily support the weight of the riser (including internal fluids). Tensioners are supported by the deck structure of the rig and interact with the riser directly.

Compensation systems are used to support the weight of a drill string (when drilling) or a completion/workover riser during connected operations. Compensation systems are supported within the rig’s derrick and typically interact with upper package or additional surface equipment.

Tension variations may influence wellhead fatigue. The manufacturer of tensioning/ compensation systems should provide details for characterizing the stiffness and damping, which may depend on the mean tension setting, initial cylinder stroke assumed (for passive systems only), and rig heave amplitude/period. If these details are not available, the manufacturer should provide additional information.

Examples for types of tensioning/compensation system include (but are not limited to) the following:

— tensioning systems:

— wire-rope— direct-acting cylinders— cassette— ram-style— air/buoyancy cans, etc.

— compensation systems:

— crown-mounted compensator (CMC)— active heave drawworks (AHD)— compensated lift frame, etc.

Table A-3 lists information required to describe each tensioning system e.g., type, number/rating, attachment point, etc. Table A-4 lists information required to describe any compensation system e.g., type, rating, limits, etc.

3.3.4 Additional surface equipmentFor some completion/workover (CWO) operations, surface equipment in addition to any upper package e.g., surface flowtree, etc. could be installed within the rig’s derrick to facilitate e-line/wireline or coiled tubing (CT) operations, such as shown in Figure 3-3. This equipment typically consists of a lift frame and the stack-up of components inside it. The stack-up within the lift frame may be dependent on the CWO operation being performed, although typically CT mode requires the tallest/heaviest stack-up. When installed, the surface equipment interacts with the rig through the compensation system and with the upper package through a set of elevators/bails and/or a connector.

The lift frame and its internal stack-up can have considerable mass/weight compared to the riser components it interfaces with and may influence loads experienced by the riser and the surface/subsea wellhead system. Table A-5 lists information required to describe any lift frame e.g., drawing, length/weight properties, types of attachments, etc. Similarly, Table A-6 lists information required to describe any stack-up within the lift frame e.g., drawings, structural/weight properties, etc.

3.3.5 Upper packagesIn the context of this document, an upper package is a collection of equipment for the purpose of well control i.e., pressure containment or shut-in. Upper packages may either be free-standing or supported by a tensioning/compensation system, and they have significantly greater mass and stiffness than riser components and wellhead/casing system. Upper packages interact with the riser system or surface wellhead system through connectors.


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Components for the upper package vary for different operations and may include a surface BOP, surface
flowhead, surface tree, spools/crossovers, among others. Table A-7 lists information required to describe any upper package e.g., GA drawing, length/weight properties, stiffness values, etc.

3.3.6 Riser joints/componentsA riser is the conduit between the rig and the well and is used for fluid transport, pressure control, and running the drill string/casings/tools. Typically, most of the riser length is comprised of standard joints/pipe having uniform dimensions. Various types of specialty joints e.g., telescopic joint, stress joint, keel joint, etc. are placed in the riser string for various reasons, such as transition between components having different stiffnesses. The riser joints/components interact with the rig through the tensioning/compensation system with constraints such as lateral guides, and with the upper/lower packages (or wellhead) through connectors or flex joints.

The riser configuration and functional requirement are different for each operation, examples of which are discussed in [3.3.2]. Refer to the following documents for examples of various riser joints/components:

— API Spec 16F, API Spec 16R, API RP 16Q, and ISO 13624-1/2 for drilling risers— API RP 17G for completion/workover risers (both XT-mode and TH-mode)— API STD 2RD for production risers.

Table A-8 lists information required to describe each riser joint/ component e.g., material properties, length/weight properties, stiffness values, etc., irrespective of the riser type. Additional information is needed based upon the function of the riser. Examples of information specifically required to describe joints/components of a drilling riser include those listed in Table A-9 e.g., GA drawing, loadsharing properties, foam diameter, etc. Similarly, Table A-10 lists examples of information needed to describe each joint/component of a completion/workover riser or a top-tensioned production riser e.g., GA drawing, multi-tube arrangement, etc.

3.3.7 Flex jointsMarine riser systems typically include two or three flex joints: an upper flex joint (UFJ) just below the diverter housing, a lower flex joint (LFJ) as part of the subsea stack, and sometimes an intermediate flex joint (IFJ). Their purpose is to reduce the bending moments generated at critical structural interfaces. Flex joints include elastomeric components with steel interleaves and exhibit time dependent non-linear viscoelastic properties, which may influence wellhead fatigue damage.

Table A-11 lists information required to describe any flex joint e.g., location, moment-versus-rotation curve, etc.

3.3.8 Lower packagesIn the context of this document, a lower package is a collection of equipment located below the riser system and having different functions, such as interfacing with the high pressure housing of the wellhead system, control or shut-in of the well, an unplanned/emergency disconnect, for example. These lower packages have significantly greater mass and stiffness than riser components and the wellhead/casing system, as well as large profile areas on which hydrodynamic forces act. The lower package interacts with the riser and subsea wellhead system through connectors.

The type of lower package varies for different riser systems. A drilling riser includes a LMRP and BOP stack i.e., subsea stack. Openwater CWO risers typically include an LRP/EDP assembly. Some production risers may include a subsea isolation device (SID). A subsea tree (XT) or various spools/crossovers may be connected to the subsea wellhead system. Those discussed above are merely examples of possible lower packages.

Table A-12 lists information required to describe any lower package e.g., GA drawing, length/weight properties, stiffness values, etc.

3.3.9 Wellhead systemA wellhead system includes the high and low pressure wellhead housings with lock-down or pre-load


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mechanisms, intermediate casing hangers, housing extensions, welds, and secondary appurtenances
(padeyes, slope indicators, cement return lines, etc.). A wellhead system interacts with the lower/upper package through a connector and with the casing system through hangers, welds and connectors.

Table A-13 lists information required to describe each wellhead system e.g., stack-up drawing, elevations and structural dimensions of components, fatigue characteristics, etc.

3.3.10 Casing systemThe casing system includes the conductor casing, surface casing, intermediate casing strings, welds and connectors, and cement. In some instances, additional casing sizes are placed between the conductor and the surface casings. The casing system interacts with the wellhead system through hangers, welds, and connectors and with the soil through the conductor casing.

Table A-14 lists information required to describe the casing system e.g., stack-up drawing, material/structural properties for each string, fatigue characteristics, etc.

3.3.11 Subsea template structureIn some instances, a subsea template structure may be used as a guide during conductor installation.

Table A-15 lists information required to describe the subsea template structure (e.g. radial gaps, stiffness, etc.).

3.4 Site-specific details

3.4.1 Operational data requirementsOperational data describes the time associated with each riser system being connected to the wellhead. Three levels of assessment may be considered during the design and operational life of the wellhead system, as listed below.

— Preliminary design and analysis – Since many inputs may not be known/finalized e.g., rig, time of year operations will be performed, etc., analyses for this assessment are based on the use of preliminary data or assumptions covering the range of uncertainty e.g., density of contents and corresponding tensions, vessel/RAO headings, metocean conditions etc.

— Detailed design and analysis – This assessment accounts for all details finalized prior to commencing operations e.g., various types of operations and associated start/end dates. Any updated rig and system configuration details may also be used. Typically, site specific scatter diagrams (for waves, current profiles, and/or wind) are used to describe long-term environmental conditions.

— Hindcasting – This assessment incorporates actual system configuration, recorded operating parameters, and measured environmental conditions.

Table A-16 lists examples of information required for the entire schedule of connected operations e.g., combinations of rig and system configuration, operating parameters, etc. Selections should reflect the level of assessment to be performed.

3.4.2 Soil propertiesSoil interaction is important in assessing the load and stress distribution in the wellhead and casing systems. Soil properties can be obtained from site-specific soil borings. Lowerbound and upperbound properties of the soil may be defined, or a single “best estimate” may be available. Dynamic stiffness or damping characteristics (due to any hysteretic effects) of the soil may be accounted for. Moreover, analysis models may include soil resistance in both the lateral and vertical directions.

Table A-17 lists information required to create P-Y curves describing soil properties for each unique strata e.g., clay, sand, etc.

3.4.3 Environmental conditionsEnvironmental conditions are described by unique combinations of sea state (or waves), current and wind that occur simultaneously for the specific site. Fatigue calculations may be based on annual conditions or


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reflect the expected start/end date of operations e.g., selection of seasonal or monthly conditions.
Environmental limits for disconnect criteria e.g., cut-off values for wave height, surface current velocity, etc. may be accounted for. Directionality of the sea state, current and wind relative to the rig may also be considered.

Long-term sea state conditions are typically described by a wave scatter diagram comprised of individual sea state bins. Short-crested wave conditions i.e., including wave spreading may be incorporated. Wellhead fatigue response can be sensitive to the periods and directions of individual waves. In some regions of the world, sea state conditions include contributions from both local seas and swell. For this reason, the spectral modelling of the seas and associated details (for each sea state bin) should be selected appropriately.

Fatigue response of the wellhead/casing system may be sensitive to the amount of drag loading experienced along the length of the riser system. Increased drag loads within the wave zone may amplify dynamic responses, while increased drag loads below the wave zone produce damping and thus may decrease dynamic responses. For this reason, the use of current as part of wellhead fatigue analyses should be carefully considered.

Weather bins should be defined for any unique combinations of the information listed in Table A-18 e.g., probability of occurrence, sea state, current, etc., which are then used with vessel mean position and any low-frequency motions.


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SECTION 4 SYSTEM MODELING AND RESPONSE
4.1 IntroductionThe goal of a wellhead fatigue analysis is to predict the fatigue damage in system components for the life of the well. For this purpose, operational inputs are appropriately applied to engineering models of systems and sub-systems to predict local responses, which are then combined with material properties and damage models.

At the highest level, this process can be illustrated by a simple flowchart, as shown in Figure 4-1. Inputs to the analysis include environmental conditions, operational data, system descriptions, and material properties, which are discussed in Sec.3. As illustrated, the analysis process consists of:

— computing cyclic loads experienced in the wellhead/casing system — relating cyclic loads to cyclic stresses for each location of interest— using a damage model to calculate fatigue life at each location of interest.

The analyses could be performed using a single fully-integrated model. However, a first level of de-coupling is typically performed by using RAO information (and low frequency motions) to characterize rig motions. Figure 4-2 (a) shows a method herein referred to as a coupled approach, where the global and local analysis models are combined to determine system responses. Due to complexity, global and local analyses may be performed separately as illustrated in Figure 4-2 (b), herein referred to as a de-coupled approach. The de-coupled approach provides an equivalent representation of the wellhead/casing system with soil, as a boundary condition in the global analysis model. De-coupling can be implemented at different locations along the system e.g., top of HPH, mudline; however, care should be taken to properly account for dynamic response of any lower package.

As illustrated in Figure 4-3, the actual workflow for wellhead fatigue analysis may take many forms, depending on the degree of integration or discretization among the different analysis models and tasks. Flowcharts illustrating the most widely used methodologies can be found in App.B. The following sections provide guidance on analysis topics (both general and specific to global/local models), damage models, and fatigue calculations. It is essential that the selected methods and assumptions account for the important physical effects that influence the fatigue damage, including non-linear behaviour.

Several example locations of interest within the wellhead/casing system (shown in Figure 4-4) to be evaluated as part of fatigue analyses include:

— welds and thickness transitions on the conductor casing and LPH— welds and thickness transitions on the surface casing and HPH— external fillet and tack welds for lifting lugs, padeyes, and brackets— lockdown between the high and low pressure housings— mechanical connectors (and associated welds) along the casing strings — changes in geometry within the base material of the wellhead housings or casing strings e.g., profile

grooves for mating to wellhead connector or running tools, threads, etc.— connection between riser system (including subsea stack, XT, etc.) and the HPH— crossover spool/adaptors based on profile of subsea stack, XT, etc.— casing/welds near top of cement— template interface.


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Figure 4-1 High-Level flowchart of wellhead fatigue analysis process


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Figure 4-2 Example methods for integrating/separating global and local analyses


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Figure 4-3 (a): In left column, examples of important items for system and global model. For each item, alternative characteristics and method options when conducting wellhead fatigue analysis.


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Table 4-3 (b): In left column, examples of important items for local model and fatigue damage calculation. For each item, alternative method options when conducting wellhead fatigue analysis.


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Figure 4-4 Example locations of interest within the wellhead/casing system


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4.2 General considerations
Wellhead fatigue analysis should be guided by the observations and recommendations listed below.

— A detail that is “conservative” in one situation may not be in another.— Appropriate modelling techniques/parameters must be selected and justified:

- If warranted, learnings from measured data may be accounted for in design and analysis.

— Sensitivity analyses on key parameters should be performed.

Moreover, documentation should provide a clear summary of all inputs/assumptions used so that results can be readily interpreted, better understood, and reproduced if necessary (such as for verification).

The following sections discuss other general considerations applicable at multiple levels within the wellhead fatigue analysis process e.g., global model, local model, etc.

4.2.1 Selection of assumptionsSelection of analysis methods should strive to achieve a balance between efficiency and accuracy. Consequently, assumptions and simplifications are unavoidable and should be clearly stated. It is generally advisable that the geometry of the riser, wellhead, and casing systems be simplified to remove unnecessary details at each level of analysis. However, sufficient detail must be retained in and around possible fatigue hot spots when performing analyses to predict local surface stresses.

For a preliminary design (as discussed in [3.4.1]), frequently a complete set of required inputs described in Sec.3 is not available and thus assumptions must be made. In this situation, selected assumptions, specifically based on missing inputs, should be verified at a later stage e.g., detailed design, etc. once information is available.

4.2.2 Mean loadsMean loads can have a significant effect on global system response e.g., natural periods, etc. and local response e.g., stress or load transfer functions, SAF, etc. Some of the possible mechanisms for mean loads to affect system response include:

— Mean riser tension can influence mean bending loads and stiffness of the system.— Mean (background) currents can provide damping and mean bending loads.— Mean vessel offset may influence riser tension, mean bending loads, and gap opening/closure.— Flex joint stiffness may be a function of mean angle.— Sequence of well construction (including casing hang-off weights and wellhead inclination) and pre-load

of the wellhead system can significantly affect response and should be considered. Partial or total loss of pre-load in the wellhead system (due to dynamic loads), can influence load transfer and fatigue hotspots.

— Initial gap closures/openings in the wellhead system/templates, as well as subsequent changes from dynamic loads, can influence stiffness of the system.

— Soil response may be a function of mean displacement i.e., influenced by mean loads.

4.2.3 Soil propertiesSoil properties are critical input to the system analysis and should be appropriately modelled (using details described in [3.4.2]) to characterize response during operations. The most common means of modelling the soil-structure interaction is a set of discrete non-linear springs applied at depths along the conductor casing, although other approaches may also be used e.g., soil continuum, etc. Moreover, calculations should reflect whether the conductor casing is jetted/driven in i.e., soils act on conductor casing diameter or drilled and cemented i.e., soils act on hole diameter. Other effects such as dynamic stiffness and damping characteristics of the soil (due to hysteretic effects) may be considered when site-specific data is provided.

The most common methods used to represent soil properties in the lateral and vertical directions are P-Y curves and T-Z curves, respectively. Various methods are available for modelling of soil properties, and the following methods, among others, can be used:

— API RP 2A


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— proprietary approaches/methodologies.
Soil data needs to represent the change of properties with depth. If available, characterization of the given soil data as applicable for monotonic (static) or dynamic conditions should be considered.

Given the uncertainty in soils data and complexity of its behaviour, it is prudent to consider multiple combinations of soil properties e.g., lowerbound/upperbound, “best estimate”, etc. and non-linear representations.

4.2.4 Cement levelResponses are sensitive to the presence or absence of cement between the casings i.e., the cement level. The actual cement levels should be modelled, if known. Otherwise, a sensitivity study on cement levels may be required. The possibility for top of cement being at (or near) a weld or connector is of particular concern.

The primary effect of cement is to transfer radial loads among casing strings. Furthermore, secondary effects of the cement, such as friction, axial load transfer, and the stiffness of the cement itself, are sometimes considered.

4.2.5 Non-linear effectsNon-linear effects may be included explicitly in the global and local response analyses or response linearization (considering appropriate mean and alternating loads) may be performed given proper validation.

4.2.6 Special-purpose simulationsSpecial-purpose simulations may be required to better understand consequences of a specific scenario. Examples of such scenarios include the following:

— “continuous exposure” to a given set of conditions, i.e., single event fatigue

— damaged riser system or well system

— blowout containment or other emergencies.

4.2.7 Representation of outputsWellhead loads and stresses may be represented in any of the following formats, independent of analysis method:

— time histories:

— retain phasing and mean value information

— can be generated from TD or FD analyses.

— histograms:

— phasing among response e.g., load components is lost

— mean value information is usually not retained

— cycle counting captures phasing but not mean effects

— can be generated spectrally e.g., Rayleigh, Dirlik, etc.

— can be performed on time histories.

— statistical values:

— typically consists of a list of root mean square (RMS), mean, and zero up-crossing period (Tz) values for each combination of response type and unique weather bin

— Phasing among response e.g., load components is lost.


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4.3 Global analysis model
4.3.1 PurposeFor a coupled approach as shown in Figure 4-2 (a), the analysis directly provides sectional loads/stresses at locations of interest within the wellhead/casing system. For a de-coupled approach as shown in Figure 4-2 (b), the global analysis provides loads imposed to the wellhead/casing system by the riser.

4.3.2 Analysis typeGlobal analysis can be performed using time-domain (TD) or frequency-domain (FD) solutions. Ignoring considerations outlined in this section (and sub-sections) may produce incorrect results.

For either type of solution, the wave spectrum should be idealized with a sufficient range and number of frequency components i.e., selected frequency content and time step to:

— accurately represent spectral nature of the sea state— capture any natural frequencies of the system— reflect the variation of vessel motions with frequency.

Regular wave analysis is not generally recommended for wellhead fatigue analysis due to the irregularity and spectral nature of actual sea states.

4.3.2.1 Time-domainA time-domain (TD) solution can provide a more accurate representation of non-linear behaviour. TD analysis requires simulating the wave time history appropriately and determining response time histories and statistics correctly. For this purpose, specific guidelines should be followed to:

— maintain independence of signal through selection of simulation length— select appropriate ramp-up time for application of loads/motions and provide additional simulation time

for decay of initial transients— have a reasonable sample size through selection of simulation length relative to the longest natural

period of rig or connected system— ensure that the random nature of responses/damage to spectral wave conditions is captured adequately

through the selection of number of realizations.

It is recommended that satisfaction of the above guidelines are demonstrated.

4.3.2.2 Frequency-domainA frequency-domain (FD) solution is intended for linear systems. Analysis of non-linear systems using FD methods requires special consideration of the non-linearities, such as the following examples:

— The drag term in Morison’s equation is typically modelled using a linear model with coefficients determined by statistical linearization.

— Non-linear stiffness effects may be considered by solving the non-linear statics problem and then linearizing at the mean response.

— Sensitivity to gaps can be assessed by modelling as fully-open versus fully-closed, which is a means of bounding responses.

If validation of any non-linear behaviour is warranted, time-domain solutions can be used to further investigate the significance of non-linear effects on critical responses e.g., wellhead loads/damage, etc.

4.3.3 Modelling considerations – rig Details used to characterize the rig e.g., vessel RAOs, shielding effects, and tensioning/ compensation systems) must be selected appropriately.

4.3.3.1 Vessel motion RAOsVessel RAOs should be described using the information listed in [3.3] to characterize rig motions. Rig motions are critical in predicting responses of a connected riser, can excite resonant response of the


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wellhead/casing system, and thus influence well system fatigue damage. Quality of RAO data near any
natural periods, including the wellhead/casing-lower package sub-system, should be reviewed. Moreover, the RAO reference point must be properly accounted for. The importance of vessel RAOs (as opposed to direct environmental loading on the riser system) can be assessed by removing all rig motions and comparing the wellhead responses.

Rig motions are sensitive to wave direction; therefore, it is prudent to consider RAOs based on a range of headings for all operational conditions. In some regions, sea state conditions include contributions from both local seas and swell i.e., bi-modal spectrum, and selection of vessel RAOs should properly account for their direction (which may not be the same). Lastly, heading of a moored rig is determined when the mooring system is deployed, and vessel RAOs should be selected based on the rig heading relative to the environmental loads direction.

4.3.3.2 Coupled motions modelA coupled motions model is another approach for determining motions of the floating rig, which accounts for any mooring lines (and/or installed risers) that are attached.

4.3.3.3 ShieldingIn some situations, the riser system may be partially shielded by the rig structure e.g., moonpool/keel of drillships, pontoons of semisubmersibles, legs of jack-ups, along length of spar, etc. or by other deployed strings/risers. Shielding affects the hydrodynamic loads experienced by the riser, thus may influence fatigue damage experienced by the wellhead/casing system.

The effects of shielding could be accounted for in the selection of the following:

— Cd or drag diameter of appropriate riser joints/components— Ca, Cm, or inertial diameter of appropriate riser joints/components, and/or— “apparent” velocity of current at appropriate depths.

It is recommended to assess how the modelling of shielding influences wellhead responses. Further review may be warranted if results are sensitive to any of these assumptions.

4.3.3.4 Tensioning/compensation systemsEach tensioning/compensation system should be modelled based on information listed in [3.3] to characterize its response during operations. Tension variation, induced by its stiffness/damping characteristics, may influence wellhead loads. In some instances e.g., use of CMC, AHD, etc., it may be sufficient to assume tension is constant.

Tension variation may be prevalent for certain tensioning systems e.g., direct-acting or for low mean tensions (expressed a percentage of the system’s capacity). In addition, for some situations, it may be adequate to model reduced number of “equivalent” tensioners, as opposed to each individual tensioner.

4.3.4 Modelling considerations – riser system Each portion of the riser system is represented by elements using equivalent properties. Therefore, model details, including mesh selection must be chosen such that mass (including contents), effective weight (including contents), and stiffnesses (axial and bending) are appropriately accounted for. Any lines external to e.g., choke/kill lines of a drilling riser, etc. or internal to e.g., inner casing of a production riser, etc. the primary cross-section of riser joints/components should be considered. Boundary conditions must be carefully selected. Lastly, prudent judgment must be applied in the selection of other assumptions as part of global riser analyses e.g., hydrodynamic properties, structural damping, etc.

4.3.4.1 Axial and bending stiffnessThe axial stiffness and bending stiffness for each portion of the riser system should be based on information listed in [3.3]. The selection of axial and bending stiffness influences predicted riser displacements and thus the loading applied to the wellhead/casing system.

Most drilling risers (such as the example depicted in Figure 3-2) include a number of external peripheral lines e.g., choke/kill lines, etc. Loadsharing capabilities of each individual line are influenced by the mean top tension, elevation and static/dynamic responses, including the plane of bending. The presence of peripheral lines and any corresponding loadsharing may be appropriately reflected in the selection of equivalent axial and bending stiffness values.


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Some risers, such as the example completion/workover riser depicted in Figure 3-3, may include several
external lines e.g., annulus umbilical/line, controls umbilicals/line, etc. Many of these additional lines are flexible with low bending stiffness and are loosely attached by intermittent clamps or straps. For this reason, it is common to assume that these flexible lines provide no additional axial/bending stiffness, i.e., all loads are carried by the primary cross-section.

Some top-tensioned production risers such as examples depicted in Figure 3-5 to Figure 3-7 may include multiple internal lines e.g., in concentric arrangement, etc. These individual lines may be modeled, or appropriate equivalent axial and bending stiffness values can be selected for the riser to reflect their presence (including any centralization, clearances, etc.).

Any upper/lower package is typically quite rigid or stiff compared to riser joints/ components; however, care should be taken that the given stiffnesses are reasonable. In some instances, it may be appropriate to use varying stiffness values to represent different cross-sections along its length.

4.3.4.2 Strings inside a drilling riserIt is common to have the following strings inside the drilling riser during certain operations:

— drill string and casing during the well construction sequence — landing string i.e., component of a completion/workover riser in TH mode during completion or workover

operations— coil tubing string inside the landing string.

Weight of these strings is generally supported by the rig’s compensation system. The friction force between the two strings is negligible in most applications. For these reasons, these components do not significantly influence the axial stiffness of the riser system.

The user should determine if effects of the internal string are important to system responses, and if so, how to represent/model it with proper validation e.g., equivalent mass along drilling riser, tension distribution, pipe-in-pipe model, selection of flex joint rotational stiffness, etc.

Some components of a completion/workover riser (XT mode) can be quite large or even be centralized within the drilling riser’s inner diameter e.g., riser sealing mandrel, wear sleeve, SSTT, etc. Certain operations will place these components across the flex joints. Potential for contact/binding may be considered in selection of bending stiffness for the drilling riser, as well as any potential influence on flex joint rotational stiffness.

4.3.4.3 Flex jointsThe flex joint should be modelled using the properties described in [3.3] e.g., position of centre of rotation of flex joint to characterize its response during operations. This may be achieved by using the manufacturer provided non-linear moment vs. angular rotation curve. Also, stiffness linearization may be performed, considering appropriate range of flex joint angles. Other effects such as damping and dynamic stiffness (load-unload) characteristics should be considered.

4.3.4.4 Boundary condition representing compliance of wellhead/casing system with soil The riser system terminates at the wellhead/casing system, and the casing system interacts with the soil. There are a number of methods for including compliance of the wellhead/casing system with soil as a boundary condition in the global analysis model. Examples of techniques used include:

— set of non-linear lateral springs along length of the conductor casing— set(s) of linearized lateral springs along length of the conductor casing— equivalent wellhead stiffness beam model (per ISO 13628-7) to represent compliance of soil/casing

interaction— equivalent lateral and rotational springs applied at a reference elevation (typically mudline)— point of fixity at some depth below mudline.

Current and mean vessel offset produce mean soil engagements, while rig surge and sway motions cause dynamic oscillations amount this mean soil engagement. These contributions result in a range of soil engagements (including both mean and dynamic effects), which should be considered when modelling compliance of the wellhead/casing system with soil.


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All of the considerations discussed above can influence natural periods of the wellhead/casing-lower
package sub-system. The natural period of this sub-system is a critical parameter for determination of wellhead responses and thus fatigue damage estimations.

4.3.4.5 Hydrodynamic propertiesHydrodynamic properties influence predicted riser response and thus the loading applied to the wellhead/casing system. The hydrodynamic properties assumed for each portion of the riser system should be based on information listed in [3.3] e.g., GA drawings, etc. and good engineering judgment/experience. The selection should account for the presence of any external lines, e.g., choke/kill lines, etc. Hydrodynamic properties are not the same in the lateral and vertical directions and can vary with Reynold (Re) and Keulegan-Carpenter (KC) numbers.

The hydrodynamic force (per unit length) of a moving riser system in an unsteady wave/current is characterized by Morison’s equation, which was derived for a moving circular cylinder. As part of this formulation, the following inputs must be assumed for each component of the riser system:

— related to drag loading:

— hydrodynamic diameter— drag coefficient (Cd).

— related to inertia loading:

— inertia diameter (or inertial area)— added mass coefficient (Ca)— inertia coefficient (Cm).

Note that the drag diameter and inertia diameter for a given joint/component are not necessarily the same and can be influenced by multiple lines/cross-sections e.g., choke/kill lines along a slick joint of a drilling riser.

Selection of hydrodynamic properties used in Morison’s equation to represent non-cylindrical components e.g., lower packages such as the subsea stack, XT, etc. should be justified.

Added mass influences natural periods of the system. Special care is recommended when selecting added mass of the lower packages. This assumption is critical to the prediction of natural periods for the wellhead/casing-lower package sub-system and thus fatigue damage estimations.

Fatigue loads applied to the wellhead/casing system (due to waves and rig motions) can be sensitive to the amount of drag acting over the riser system. Wave-induced drag in the wave zone can excite dynamic responses, while increased drag below the wave zone (due to current) can dampen out dynamic responses over the remaining length. Therefore, care should be taken in selecting appropriate combinations of hydrodynamic diameter, assumed Cd, and current profile for wave induced fatigue models.

Since a wide range of approaches are used in the selection of these hydrodynamic properties, guidance can be found in the following references:

— API RP 16Q— ISO 13624-1/2— DNV-RP-C205— DNV-RP-H103.

Selection of hydrodynamic properties can also be made through tank tests or computational fluid dynamics (CFD) simulations at full-scale Re and KC values. Appropriate care and considerations are needed to ensure reliable test and CFD results.

4.3.4.6 Structural dampingAny form of damping on the riser system reduces dynamic response of the wellhead/casing system. Because limited data is available for riser systems, structural damping to be applied in the global analysis model (if any) should be selected appropriately. At present time, the best means for quantifying the amount


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of structural damping is through testing or in-situ measurement. In lieu of data, it is recommended to
include the minimum amount of structural damping that can be justified. Typically, for wave fatigue response, total damping (in the lateral direction) along the riser system is dominated by hydrodynamic effects due to current and wave forces. Structural damping in the axial direction is different from that in the lateral direction.

4.3.5 Modelling considerations – environmental conditions and operating parametersEnvironmental conditions applied should reflect information listed in Sec.3. Modelling considerations used to represent sea states (including wave spectrum) and current, as well as mean vessel offset(s), should be selected appropriately. Directionality of environmental loads (relative to the rig) should also be considered.

4.3.5.1 Wave spectrumThe selected wave spectrum should reflect wave environments at the specific location. For example, wave conditions in the North Sea are often described using the JONSWAP (unimodal) or Torsethaugen (bimodal) definitions. As also discussed in [4.3.2], the wave spectrum should be idealized with a sufficient range and number of components to accurately represent the sea state, as well as capture the riser natural frequencies and the variation of vessel RAOs with frequency.

4.3.5.2 Sea statesAll relevant sea states should be applied as part of global analysis. This includes the following considerations:

— Selecting appropriate values from a given Hs and Tp range when a wave scatter diagram is provided, e.g., a particular sea state bin defined as Hs of 2.0-3.0 meters and wave Tp of 8-9 seconds:

— Each bin could be characterized by one of 9 combinations for lowerbound, average, and upperbound vales of Hs and Tp.

— Any known operational limits can be incorporated, with a corresponding update in probability of occurrence for each sea state. Examples include:

— If a riser system is disconnected under specified operating limits (such as the 10-Year event), any sea state(s) larger than this event does need to be considered, since no fatigue damage will be accumulated by the wellhead/casing system.

— If the riser system will only be connected during specific timeframes i.e., expected start/end dates are known, analyses may consider seastates described by monthly or seasonal wave scatter diagrams, as opposed to annual conditions.

— Short-crested waves i.e., wave spreading can be modelled, as opposed to assuming long-crested waves:

— For rigs with un-symmetrical motion characteristics (such as drillships), accounting for short-crested waves can increase predicted motions at favourable headings.

The wave period has an important effect on riser responses and thus wellhead/casing fatigue damage. Dynamic responses are amplified (due to possible excitation of resonant response) when the wave period coincides with natural periods of the rig or connected system. The following dynamic responses typically occur at different wave periods:

— rig motions

— excitation of the riser mode(s)

— excitation of wellhead/casing-lower package sub-system mode.

Therefore, if sub-blocking is performed, it is critical that all of these dynamic responses are appropriately captured through grouping of weather bins and wave period selections.


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4.3.5.3 Current
Fatigue damage experienced by the wellhead/casing system is influenced by the amount of current-induced drag acting on the riser system, which is a net effect of the following:

— hydrodynamic diameter (see [4.3.4.5])— drag coefficient (see [4.3.4.5])— shielding (see [4.3.3.3])— current profile.

As discussed in [3.4.3], neglecting current may not always overestimate dynamic wellhead loads; therefore, care should be taken in selecting appropriate current profiles.

4.3.5.4 DirectionalityA weather bin is any unique combination of waves, current and wind that occur simultaneously, each of which may have a different direction. Directionality of weather can influence the riser response and fatigue damage experienced by the wellhead/casing system.

A common approach is to initially assume that fatigue damage is accumulated in a single plane of the wellhead/casing system’s cross-section. However, any directionality of weather would distribute fatigue damage around the circumference of the wellhead/casing system’s cross-section.

It is prudent to consider directionality of weather, if given in the site-specific metocean definition. Examples for how directionality (of weather) can be incorporated are listed below.

— All waves (seas and swell), current profile, and wind are assumed collinear.— All waves (seas and swell) and wind are acting in the same direction, but current profile is acting in

another direction.— Swell, wind (and associated local seas), and current profile are each from unique directions.

Moreover, the direction of the current profile may vary with depth.

4.3.5.5 Mean vessel offsetMean vessel offset is induced by environmental loads and controlled by the rig’s station-keeping capabilities, i.e., DP or moored. This is an important consideration, since it influences mean loading as part of both global and local analyses, as further discussed in [4.2.2].

If the rig is DP, the mean vessel offset should reflect past experience and planned operations. Note that the rig may not always be located over the well, such as when positioned in the up- or down-current directions to improve flex joint angles. For moored rigs, provided mean vessel offsets may be applied for appropriate operating conditions e.g., sea states, etc. Failed mooring line(s) may require re-assessment such as the examples of special situations listed in [4.2.6].

Horizontal distance between the surface location (at wellbay slot on rig) and the subsea wellhead location is another consideration (similar to mean vessel offset) for some riser systems, e.g., used for drilling/production operations from a spar, TLP, etc.

4.3.6 Typical outputsTypical outputs for the coupled approach are the same as described in [4.4.2.4] (for local analysis models). For the de-coupled approach, global analysis provides loads imposed to the wellhead/casing system by the connected riser. These typical outputs i.e., “wellhead loads” include contributions from tension, bending moment, and shear force at the datum selected for transfer function definitions (as further discussed in [4.4.2.4]).

Mean and dynamic responses can be expressed in several formats as discussed in [4.2.7] e.g., time histories, histograms, statistical values.

Examples of other typical outputs that can be helpful in understanding global responses of the connected system and predicted wellhead loads (and thus fatigue damage estimations) include the following:

— rig motions at rotary— static (or mean) responses, including flex joint angles (if applicable), distributions of lateral

displacement, effective tension, bending moment, shear force, etc. along length of connected system


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— natural periods and mode shapes characterizing resonant response of the connected system (of
particular interest is the wellhead/casing-lower package subs-system)— dynamic system responses, including flex joint angles (if applicable), distributions of lateral

displacement, effective tension, bending moment, shear force, etc. along the length of connected system.

4.4 Local analysis model(s)

4.4.1 PurposeThe purpose of local analysis models of the wellhead/casing systems is two-fold: to determine the load transfer among system components (system analysis) and to determine local stress distributions (detailed analysis). Unlike global analyses, local analysis solutions are typically static solutions in which monotonically increasing loads are applied.

For the coupled approach as depicted in Figure 4-2 (a), the local analysis model is integrated into the global analysis model. For the de-coupled approach as depicted in Figure 4-2 (b), the local analysis model is separate from the global analysis model, and loads/stiffness are defined at a suitable datum point e.g., at or near the top of the wellhead system.

The local response analysis itself may be accomplished using a single, comprehensive and detailed model of the entire system, but it may be impractical to include sufficient geometric detail or mesh density in the system response analysis model. The analysis objective may also be achieved by combining two or more models, each focused on one aspect of the response, typically system analysis and detailed analysis. Some of the local response information may also be obtained through physical testing of systems and individual components.

4.4.2 System analysisA system analysis is performed to determine the load transfer among the components. These models may use 3D solid elements, beam elements or a combination of the two (hybrid models). In system response analyses, the main objective of the model is to capture the correct component stiffnesses and the mechanical interactions among them. A comprehensive system analysis should consider the following details for all operations and corresponding system configurations:

— geometric non-linearities— soil and template interactions— sequence of construction — pre-load e.g., rigid lockdown, active lockdown, bootstrapping— cement levels— mean loads.

Additional modelling considerations specific to each of the major subsystems are provided below.

4.4.2.1 Wellhead systemThe wellhead system should be modelled using the properties described in [3.3] to characterize its response during operations and calculate accurate surface stresses for fatigue. Consideration should be given to the orientation of non-axisymmetric features e.g. split rings or cement outlets with respect to the direction of load application.

In non-preloaded systems friction and the closing/opening of radial gaps introduce non-linearity to the system response. If radial gaps remain, the high pressure housing may rotate (to some extent) within the low pressure housing, and if so, large moments may be transmitted to the surface casing. The response of pre-loaded/bootstrapped systems may also be non-linear, particularly if load magnitudes cause the pre-load to be partially (or completely) relieved or load shoulders to partially (or completely) separate. Friction can also influence response of pre-loaded system.

4.4.2.2 Casing systemThe casing system should be modelled using the properties described in [3.3] to characterize its response


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during operations and calculate accurate surface stresses for fatigue. The model should extend to a
sufficient depth below the mudline, such that stresses at areas of interest are not influenced by the model termination. Inner casings may be modelled explicitly, or the hang-off weights may be applied sequentially at the hang-off locations.

4.4.2.3 TemplateIf a template is present, the lateral and vertical interaction between the wellhead/casing system and the template may be important. This interaction is typically modelled as a spring element representing the appropriate stiffness and gap; however, more complex models may be needed in case of asymmetric template/well behaviour.

4.4.2.4 Typical outputsFor a de-coupled approach, typical outputs of a system analysis include the compliance properties of wellhead/casing/soils interaction e.g., the stiffness at the wellhead datum and stress-loading response curve relating stresses to applied loads. If the system analysis model is sufficiently refined, it may also be possible to produce load-to-stress relationship for local surface stresses directly. Otherwise, the use of SCF/SAF is required.

If the system response is linear or nearly linear, it may be possible to represent the outputs as a single value e.g., stiffness, load-to-stress ratio. Otherwise, alternate methods are required to capture response non-linearities e.g., mean load effects, loss of pre-load.

4.4.3 Detailed analysisA detailed analysis is performed to determine the local stress distribution at locations of interest.

4.4.3.1 Modelling considerationsDetailed analysis requires a fine mesh in order to predict accurate surface stresses. This may be accomplished by:

— including the fine mesh directly in a 3D solid system analysis model— using fine-mesh 3D solid sub-models — using separate fine-mesh 3D solid or 2D axisymmetric solid elements of individual components e.g.,

transition pieces and threaded connectors.

The accuracy of surfaces stresses used for fatigue analysis should be validated by mesh sensitivity studies or documented experience using the specific software, mesh density, and element type. For some details it is often possible and more efficient to use analytical formulations to calculate local stress concentrations e.g., weld eccentricity.

Detailed analysis models should consider the following effects for all operations and corresponding system configurations:

— non-linear geometry (large displacements)— finite sliding contact— friction— pre-load e.g., rigid lockdown, active lockdown, bootstrapping— temperature or internal/external pressure.

4.4.3.2 Typical outputsThe output of detailed analyses is alternating surface stresses for use in load-to-stress relationships or Stress Amplification Factors (SAF). It is generally recommended to use the range of stress perpendicular to the most likely plane of crack propagation i.e., meridional stress, which is not necessarily the same as axial stress. The load-to-stress relationship and SAF may be varying with load magnitude, and if so, appropriate methods are required to capture response non-linearities e.g., mean load effects, loss of pre-load.

A load-to-stress relationship, also referred to as stress load ratio, may provide peak surface stress directly. Alternatively, it may give stress at a reference location which, when combined with an SAF, provides peak surface stress.


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Static stress concentration factors (SCF) are only applicable when the response is linear. Use of SAF is
preferred when the majority of the expected fatigue cycles consist of stress variations about a given mean stress. The SAF represents the local slope of the peak surface stress versus reference stress curve i.e., the ratio of the incremental change of local peak stress to the corresponding incremental change of the reference stress. Any useful reference location and stress may be used in the SAF calculation, but the reference section dimensions and reference stress e.g., membrane axial stress, etc. should be clearly defined and documented.

4.4.4 TestingPhysical testing is recommended and may be required to validate the capacity and functionality of system components. Testing can also be helpful as a substitute for system response or local stress models. Load transfer and pre-load relief characteristics can be determined with carefully planned and executed assembly tests.

Local effects such as stress concentration, stress gradient, yielding, etc. can be determined by using destructive testing results to calculate a stress modification factor (SMF) as further described in DNVGL-RP-0005 (former DNV-RP-C203). Note that SMF values are a function of the fatigue curve used in the calculation and are representative of the nominal (test) geometry only. Additional FEA may be required to include the effect of geometric tolerances.

4.5 Damage modelThe stresses predicted by analysis must be combined with an appropriate damage model to predict the expected fatigue damage/life. The most common damage model used in wellhead fatigue analysis is the stress-cycle (S-N) method based on constant amplitude stress cycles, high cycle fatigue, and the linear damage accumulation hypothesis. Other damage models, such as initiation life (elastic-plastic strain) and fracture mechanics, may also be used.

4.5.1 Fatigue assessment using S-N-curvesThe applicability, requirements, and limitations of the S-N curve(s) used need to be understood. Considerations for different S-N curves include the following examples:

— materials and configurations e.g., base metal versus welds— statistical variations and probability of failure i.e., design curve versus failure curve— correction factors for:

— thickness— mean stress— surface treatment e.g., grinding— environmental effects e.g. cathodically protected versus free corroding.

— limitations such as material strength range and environment.

It is critical that the stresses calculated correspond to the stresses used to develop the S-N curve. Some S-N curves for welds include all relevant stress concentrations due to the weld itself, while others require the application of SCF due to weld details e.g., eccentricity. In either case, the stress value used must account for stress concentrations due to geometric discontinuities near the weld.

The moment-cycle (M-N) fatigue method is a variation of the S-N method sometimes applied to system components such as connectors. M-N curves are a combination of S-N curve and SAF/SCFs for a specific component or detail cross-section.

4.5.2 Fracture mechanics The fatigue life may also be established using a fracture mechanics-based assessment, also referred to as an engineering criticality assessment (ECA), which assumes that an initial flaw is located at highly stressed regions of the system. By idealizing the flaw as a sharp-tipped crack and orienting it according to the maximum cyclic stress, the crack growth rate can be predicted as a function of applied loading, including crack face pressure where applicable. A failure assessment diagram (FAD), which assesses the tendency of


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material failure due to both fracture and plastic collapse, is used to establish the maximum permissible
crack size which can sustain the peak loads.

As further described in API 579 and BS 7910, fracture mechanics relies on accurate material properties, especially fracture toughness, and representative crack growth parameters for the specific operating environment e.g. cathodic protection, sour service, etc. Furthermore, for welded regions, material property variation in the heat affected zone (HAZ) and any residual stresses should be accounted for.

Two common approaches for implementing a fracture mechanics damage model are the following:

— Fatigue life is calculated for the given initial flaw size:

— It should be noted that the value should be representative of reliable flaw detection capabilities based on the inspection equipment, procedures and personnel. More specifically, the initial flaw size should be the minimum flaw size that can be detected.

— Flaw acceptance criteria are determined for a specific fatigue life target:

— This information is used for inspection of the components.

4.5.3 Initiation life methodAnother method that has been used to calculate fatigue damage is the socalled initiation life method, which is based on an elastic-plastic strain model. This method applies to base metal locations, not to welds. The typical approach is to develop the C and m coefficients of an S-N curve fit to failure points for a specific detail in the component. This method already includes the effect of stress concentration and mean stress at the detail. The initiation life curve used for design should include allowance for statistical variations and a defined probability of failure e.g., two standard deviations.

This method relies on accurate material properties and if the information is not available for the material and environment in question, specific tests should be performed.

4.6 Fatigue calculationFatigue calculations should combine the effects of all relevant environments, operations, and system configurations to determine the total damage. The calculation of the resultant stress or damage due to the combination of various loading events is essential to properly estimating the fatigue damage.

Different operations e.g., drilling from a MODU, workover, and production are considered sequential events, whereas responses due to waves, swells, and currents can occur simultaneously. Simultaneity, however, does not necessarily imply correlation, and a distinction should be made as to whether or not simultaneous events are also correlated. Fatigue calculation in terms of accumulated damage is affected by how the loading events are classified, since that will determine whether independent damages are simply added or stresses are first combined and then damages calculated. The difference between combined damage and combined stresses is large due to the fact that fatigue damage is a 3rd or greater power function of the stress.

For fatigue calculations, the long-term distribution of stress range is developed through cycle-counting e.g., rainflow counting, etc. A stress histogram consists of an appropriate number of constant amplitude stress range blocks, each with a number of stress repetitions based on the probability of occurrence. Fatigue damage can be calculated for each individual block (of the stress histogram) and then summed together using Miner’s rule. Alternatively, in some situations having a narrow-banded response process e.g., Gaussian, etc., fatigue damage can be calculated from RMS stresses and corresponding Tz values using a closed form solution. DNVGL-RP-0005 provides further details pertaining to fatigue damage calculation from stress range history.

The basic output of wellhead fatigue analysis is usually the unfactored fatigue life. Typically, additional safety factors e.g., 3, 5, or 10 are applied to the calculated fatigue life to determine the design (factored) life. The appropriate safety factor depends on the application, the inspectability of the equipment, and the criticality of failure. While codes and standards may specify minimum required safety factors or fatigue life, an additional safety factor may also be applied.

The final result of a wellhead fatigue analysis is typically presented as unfactored or factored fatigue life


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e.g., years. However, expressing the results in other formats can be useful. For example, if the duration of
different operations is not known at the design stage, damage rates e.g., damage/year can be calculated for each operation and several possible environments. This output allows for fatigue damage to be calculated as operations progress based on actual durations and environments. Another example for the early design stage i.e., prior to final equipment selection is to calculate allowable SAF values (corresponding to a given S-N curve) for components of the wellhead/casing system. DNVGL-RP-0005 provides further details pertaining to fatigue damage calculation from stress range history.


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APPENDIX A TABULAR LISTINGS OF INPUTS NEEDED FOR
WELLHEAD FATIGUE ANALYSIS

Table A-1 Listing of information to describe the rig

Detail NotesRig nameRig type - MODUs, e.g., jack-up, semisubmersible, drillship, etc.

- FPUs, e.g., semisubmersible, spar, TLP, FPSO, etc.Station-keeping systems Is the rig moored, dynamic positioned, or has capability for both?GA drawings of hull and moonpool geometry

- typically shows the rig dimensions in the forward-aft and port-starboard directions- can definine elevations of any decks/levels or physical constraints relative to the vessel keel

Both amplitude (and corresponding phase angles) of surge, sway, heave, roll, pitch, and yaw

- recommended to be given in tabular format- recommended to be provided for multiple headings, which is the relative angle between the rig’s bow/stern and the wave direction- At a minimum, it is recommended to be provided in increment of 0.50 seconds for wave periods of 2-5 seconds and increment of 1.0 second for longer wave periods up to 40 seconds.

Water depth range for which applicable Unique sets of vessel RAOs may be provided for shallow water depths.

Vessel draft e.g., for operating, survival, transit, etc.Convention for relating response amplitude to wave amplitude

Are RAOS defined using a single-versus-single convention or a single-versus-double convention?

Units for roll, pitch, and yaw motions e.g., degrees/meter, radians/feet, etc.Coordinate system used - Is it right-handed or left-handed?

- In what direction are the various axes defined (e.g., +X axis is towards bow, +Z axis is upward, etc.)?- Does a positive Surge response correspond to motion in the +X direction?

Reference location - e.g., center of gravity, rotary, etc.- Coordinates of the reference location (within the coordinate system used) are required.

Drill floor (or rotary/RKB) location Coordinates of the drill floor location (within the coordinate system used) are required.

Convention for defining phase angles Should a positive phase angle be interpreted that a response leads or lags the wave crest?

Configuration of mooring lines/risers - only applicable when rig is moored- e.g., intact mooring (for a given set of mean tensions applied to each mooring line) with all risers installed, etc.

Gen

eral

RAO

Info

rmat

ion


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Table A-2 Examples of details to describe each system configuration
Detail NotesRotary from which operations will be performed

only applicable for rigs with two rotaries

Elevations for attachment of tensioning/compensation systems to be used

- e.g., attachment of riser tensioners to the Tension Ring (along the TJ Outer Barrel) of a drilling riser- typically expressed as relative to the mean water surface (or drill floor elevation)

Additional surface equipment to be installed, if any

-Will a Lift Frame be installed, such as for completion/workover operations?- If so, what stack-up will be installed inside the Lift Frame (e.g., E-line/Wireline, CT, etc.)?

Elevations of any constraints between the riser (or additional surface equipment) at the rig, if any

- e.g., centralizer, bushing, roller, dolly, etc.- also include corresponding radial gaps

Elevation of drill floor (or RKB) generally expressed as relative to the mean water surfaceType of upper package(s), if any - e.g., surface BOP, surface flowhead, surface tree, spools/crossover, etc.

- Is it located above or below the drill floor elevation?

Location of flex joints, if any generally described as elevation for center of rotationArrangement of various riser joints/components

based on a target (mean) space-out for the tensioning/compensation systems

Types/arrangement of lower package(s), if any

- e.g., subsea stack of drilling riser system, LRP/EDP assembly of CWO riser, subsea tree, etc.- Make sure to include any equipment located between the wellhead and the riser system.

Wellhead stick-up distance from mudline (or template) to top of high pressure housing


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Table A-3 Listing of information to describe each tensioning system
Detail NotesType/Manufacturer examples of types include wire-rope, direct-acting, cassette, RAM-style,

etc.Total number of individual tensioners - typically 8, 12, or 16 for wire-rope systems used to support a drilling riser

- usually 6 for direct-acting systems used to support a drilling riser

Number of individual tensioners to be active or attached

In some situations, it may not be necessary to pressurize/attach all of the individual tensioners to support the riser system (e.g., supporting a CWO riser using a wire-rope tensioning system).

Individual rating/capacity - e.g., 200 or 250 kips (per tensioner) for wire-rope systems used to support a drilling riser - e.g., 600 or 800 kips (per tensioner) for direct-acting systems used to support a drilling riser

Details characterizing stiffness, damping, and inertial properties

- Stiffness can characterize variation in phase with displacement. Damping can characterize variation in phase with velocity. Inertial effects can characterize variation in phase with acceleration.- Performance curves (relating tension to stroke) typically account for only gas compressions; however, damping effects (such as due to mechanical friction and pressure drops) and inertial effects (such as due to oscillatory movements of fluids) should also be accounted for.- These properties may vary with mean tension setting, initial cylinder stroke, and assumed heave amplitude/period.

Coordinates for attachment points of individual tensioners to the rig and the riser

- Attachment to the riser is often described as the diameter to padeyes on the tension ring.- For wire-rope systems, attachment to the rig is meant to be along the "line of action", which is commonly interpreted as the point at which the rope departs from the turn-down sheave.- may also be expressed as fleet angle

Details of other tensioning system components

- drawing showing dimensions (OD, ID, length) of the cylinder and piston- drawing showing dimensions and air weight of the rod- PID, etc. showing the sizes and lengths for all piping back to the accumulators

Total stroke/travel limit - e.g., 50 feet for systems used to support a drilling riser - e.g., 25 feet for systems used to support a production riser- Note that operability limits should account for any cylinder end cushioning.


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Table A-4 Listing of information to describe any compensation system
Detail NotesType/Manufacturer examples of types include CMC, AHD, compensated lift frame, etc.Purpose Is this the primary (or secondary) means of compensation?Load rating/capacity recommended to provide for both static and compensating modesLimits used for design e.g., targets for heave velocity, heave acceleration, etc.Details characterizing stiffness, damping, and inertial properties

- Stiffness can characterize variation in phase with displacement. Damping can characterize variation in phase with velocity. Inertial effects can characterize variation in phase with acceleration.- Performance curves (relating tension to stroke) typically account for only gas compressions; however, damping effects (such as due to mechanical friction and pressure drops) and inertial effects (such as due to oscillatory movements of fluids) should also be accounted for.- These properties may vary with mean tension setting, initial cylinder stroke, and assumed heave amplitude/period.

Means of attaching to riser or upper package, if applicable

e.g., set of bails/elevators, etc.

Details for each set of bails, if applicable

- load rating, length, size/diameter, and total air weight- distance between centerlines of each bail (for a given set)

Total stroke/travel limit - applicable for passive systems only- e.g., 25 feet for CMC


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Table A-5 Listing of information to describe any lift frame
Table A-6 listing of information to describe any stack-up within the lift frame

Detail NotesGA drawing of lift frame - needs to provide general dimensions for the assembly and structural

sub-components, e.g., lower/upper beams, etc. - A drawing/schematic showing the Lift Frame installed on the rig is also useful.

Is the lift frame capable of providing heave compensation?

If so, will it be used/active?

Orientation within rig's derrick typically, either the forward-aft direction or the port-starboard direction

Total length - relative to some datum - at a given stroke/travel if frame will be compensating

Total air weight - needs to include any equipment used for attachment to a compensation system and the riser, e.g., set of bails/elevators, etc.- further break-down (of the total weight) amongst each sub-component of the assembly is also helpful

Center of gravity - relative to some datum - at a given stroke/travel if frame will be compensating

Means of attaching to rig's compensation system

e.g., set of bails/elevators, etc.

Means of attaching to riser or upper package

e.g., set of bails/elevators, clamped connection, etc.

Details for each set of bails, if applicable

- including their load rating, length, size/diameter, and axial stiffness- distance between centerlines of each bail (for a given set)

Location of any hinged connections between its sub-componentsIs it equipped with a winch? If so, what is its rating/capacity?Type and location of any lateral supports back to the rig

e.g., dolly back to guiderails, etc.

Detail NotesStack-up arrangement/configuration - include a listing of all components within the stack-up (e.g., adapter

spool, BOP, stripper, lubricator, injector frame/head, etc.)- provide for each applicable type of completion/workover operation (e.g., E-line/Wireline, CT, etc.)- A drawing/schematic showing the stack-up within the lift frame is also helpful.

Effective stack-up length for each component

accounting for swallow of connectors

Total air weight and center of gravity for each component

relative to some datum

Amount of tension applied by winch on the lift frame, if applicable

generally set to provide a specified overpull at some elevation through the stack-up arrangement/configuration

Elevation of any lateral bracing back to the lift frame

e.g., platform on which a component sits


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Table A-7 Listing of information to describe any upper package
Detail NotesGA drawing general dimensions (e.g., width, depth, etc.) are requiredEffective stack-up length accounting for swallow of connectorsTotal air weight and center of gravity for each component


Inner diameter primarily referring to diameter in which contents are containedAxial stiffness - can be characterized using structural dimensions (OD/ID) or as "EA" term

- can be provided for different cross-sections (e.g., flange necks, etc.)

Bending stiffness - can be characterized using structural dimensions (OD/ID) or as "EI" term- can be provided for different cross-sections (e.g., flange necks, etc.)

Fatigue characteristics for any geometric transitions or connectors/welds to be evaluated (only applicable when evaluating surface wellhead systems)

- should consider if the component will be in air or in seawater. If in seawater, is the component freely corroding or cathodically protected?- The S-N fatigue damage model requires designation of a material fatigue curve and appropriate SAF (with its corresponding reference section). - The initiation life damage model requires material properties (i.e., type, both monotonic and cyclic properties per ASTM E606) and SAF value (with its corresponding cross-section).- The fracture mechanics damage model requires material properties (e.g., type, yield strength, ultimate strength, fracture toughness), SAF value (with its corresponding reference section), the maximum flaw size that can be missed by NDT, and the highest stress(es) produced by extreme loadings for operations during full life cycle. For welds, it is also necessary to know if post-weld heat treatment (PWHT) has been performed. Note that minimum flaw size may vary with its location (i.e., on surface or embedded) and the component's wall thickness.


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Table A-8 Listing of information to describe each riser, irrespective of type
Detail NotesListing/arrangement of all joints/components

- include all components located between the lower package (at bottom) and the upper package or additional surface equipment (at top)- also specify the type of connector/connection for each component

Material type for each joint/component e.g., steel, titanium, etc.

Specified minimum yield strength (SMYS) and ultimate strength for each joint/component

typically expressed in units of ksi or MPa

Effective stack-up length for each joint/component


Structural dimensions (OD/ID) along length of each joint/component

not accounting for specific connector dimensions

Total air weight for each joint/component

Any equipment attached to the joint/component during service (e.g., auxiliary lines clamps of drilling risers, riser protection system, VIV suppression device, etc.) should be considered.

Total submerged weight for each joint/component

- including all buoyancy effects, but neglecting any contents- Any equipment attached to the joint/component during service (e.g., auxiliary lines clamps of drilling risers, riser protection system, VIV suppression device, etc.) should be considered.

Air weight of tension ring When calculating tension requirements, the weight of the tension ring is sometimes considered as part of riser system (e.g., direct-acting systems used to support drilling risers) and sometimes considered as part of the tensioners (e.g., wire-rope systems used to support drilling risers).

Details of any riser protection system or VIV suppression device used

- Size/diameter and coverage length are required.- Examples of riser protection systems include shims, fins, etc.- Examples of VIV suppression devices include strakes, fairings, etc.

Location of any welds along each joint/component



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Table A-9 Listing of additional information to describe each joint/component of a drilling riser (operated
from a MODU)

Table A-10 Listing of additional information to describe each joint/component of a completion/workover riser or a top-tensioned production riser

Detail Further Explanation/Discussion/ClarificationType/Manufacturer The rating (e.g., 3500 kips, etc.) can also be useful.GA drawing of standard riser joint slick and when equipped with buoyancy modulesDetails of all peripheral lines - These include the Choke/Kill lines, Mud Boost line, hydraulic lines, etc.

- The number, structural details (OD/ID), and loadsharing capabilities of each line is needed.

Foam diameter typically between 54-60 inches for drilling risersGA drawing of Telescopic Joint - structural details and air weight of Outer Barrel and Inner Barrel are

required separately- effective length when fully-collapsed and fully-extended is required, . i.e. the total stroke is the difference between these two values.- where the Tension Ring attaches to the Outer Barrel (relative to some datum) is required- Air weight information needs to include any ancillary equipment attached to it (e.g., goosenecks, etc.).

Estimate for uncertainty in total submerged weight of marine riser, excluding contents

calculated from assumed values of fwt and fbt tolerance factors defined in API RP 16Q

Detail NotesWhether a concentric pipe arrangement is used?

e.g., outer/inner arrangement of a top-tensioner production riser

GA drawing for each specialty joint/component

e.g., lower stress joint, tension joint, cased wear joint, surface flowtree, etc.

Location(s) of any cross-overs or saver subs

- typically located adjacent to specialty joints - for the purpose of transitioning connection/connector type or reducing make-and-breaks performed on the speciality joint's connector

Details for any additional lines (run) alongside the primary tube (e.g., annulus line, controls umbilical, mux/hot lines, etc.)

- structural dimensions (if hard pipe) or size/diameter (if flexible)- air weight per unit length, both empty and when filled with contents- submerged weight per unit length, both empty and when filled with contents

Cross-sectional view of multi-tube arrangement, if applicable

It is useful to also show the smallest and largest diameters that include all lines of the multi-tube arrangement (for flow from various directions).

Pre-load of the inner casing/string applicable for some top-tensioned production risersDetails for mechanism used to attach/brace the additional lines to the primary tube (e.g., straps, clamps, etc.)

- individual air weight (or mass)- individual submerged weight- vertical spacing or total number used


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Table A-11 Listing of information to describe any flex joint
Detail NotesType/Model It is useful to know the maximum rotation limit.Effective stack-up length accounting for swallow of connectorsLocation for center of rotation relative to a given datum, typically the drill floorStructural dimensions (OD/ID) along length

not accounting for any connections

Total air weight (or mass) For LFJ, note the distribution below/above the center of rotation.Total submerged weight For LFJ, note the distribution below/above the center of rotation.Details characterizing stiffness and damping properties

- Stiffness can characterize variation in phase with displacement. Damping can characterize variation in phase with velocity.- Response is typically characterized by a non-linear curve relating bending moment to angular rotation. - These properties need to account for operational conditions (e.g., temperature, pressure, etc.) and may vary with amplitude/period of the angular rotation.


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Table A-12 Listing of information to describe any lower package
Detail NotesGA drawing General dimensions (e.g., width, depth, etc.) are required, which are

used to estimate hydrodynamic properties.Effective stack-up length accounting for swallow of connectorsTotal air weight and center of gravity for each component


Total submerged weight for each component

including all buoyancy effects, but neglecting any contents

Inner diameter primarily referring to diameter in which contents are containedAxial stiffness - can be characterized using structural dimensions (OD/ID) or as "EA" term

- can be provided for different cross-sections (e.g., flange necks, etc.)

Bending stiffness - can be characterized using structural dimensions (OD/ID) or as "EI" term- can be provided for different cross-sections (e.g., flange necks, etc.)

Fatigue characteristics for any geometric transitions or connectors/welds to be evaluated



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Table A-13 Listing of information to describe each wellhead system
Detail NotesStack-up drawing The relative location of components and features (including

connectors/welds), as well as gaps among components and regions of potential axial/radial contact, should be indentified.

Location and configuration of any external appurtenances

focus on any equipment that may have been welded-on at the rig, such as lifting lugs, etc.

Elevation of the top of the high pressure housing relative to a reference location

- sometimes referred to as "stick-up"- For subsea wellhead systems, the reference location may be relative to the mudline or a template.- For surface wellhead systems, the reference location may berelative to the water surface or the rig.

Specified minimum yield strength (SMYS) and ultimate strength for each component


Effective stack-up length for each component


Structural dimensions (OD/ID) along length of each component

not accounting for specific connector dimensions

Fatigue characteristics for any geometric transitions (e.g., grooves) or connectors/welds to be evaluated


Is the wellhead system pre-loaded? If Yes, then information on the pre-load mechanism (sometimes referred to as lock-down or bootstrapping) and magnitude of pre-load is needed.

Coefficients of friction at interfaces account for whether interface is coated, lubricated, etc.


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Table A-14 Listing of information to describe the casing system
Table A-15 Listing of information to describe the casing system

Detail NotesStack-up drawing needs to show the relative location of each casing string and features

(including connectors/welds)Specified minimum yield strength (SMYS) and ultimate strength for each casing string


Total effective stack-up length for eachcasing string

once any swallows are accounted for

Structural dimensions (OD/ID) for eachcasing string

neglecting any connections

How is the conductor casing installed? - Options include jetted, drilled/cemented, or driven. - If drilled/cemented, what is the diameter of the hole?

Fatigue characteristics for any geometric transitions or connectors/welds to be evaluated

- should consider if the component will be in air or in seawater. If in seawater, is the component freely corroding or cathodically protected?- The S-N fatigue damage model requires designation of a material fatigue curve and appropriate SAF (with its corresponding referencesection). - The initiation life damage model requires material properties (i.e., type, both monotonic and cyclic properties per ASTM E606) and SAF value (with its corresponding cross-section).- The fracture mechanics damage model requires material properties (e.g., type, yield strength, ultimate strength, fracture toughness), SAF value (with its corresponding reference section), the maximum flaw size that can be missed by NDT, and the highest stress(es) produced by extreme loadings for operations during full life cycle. For welds, it is also necessary to know if post-weld heat treatment (PWHT) has been performed. Note that minimum flaw size may vary with its location.

Air weight of each strings (and mudweight in each annuli) during the sequence of well construction

needs to be provided for any string (e.g., casing, liner, tubing, etc.) whose weight is transferred to the conductor casing or the surface casing

Cement levels primarily needed for (outside) the conductor and surface casings as aminimum

Detail NotesType of Seabed Fixation e.g., suction anchors, piled, etc.GA drawing should identify locations of all gaps to the wellhead/casing system (or tail

pipe, if present)Gap - needed at each location

- may be unique for various directions depending on structure designStiffness (once gap is closed) - needed at each location

- provide for horizontal translations, vertical translations, and rotations- may be unique for various directions depending on structure design


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Table A-16 Examples of information needed for the entire schedule of connected operations
Detail NotesType/Name of rig - for selection of rig details( listed in Table A-1) used in analysis

System stack-up -for selection of system stack-up details (listed in Table A-2) used in analysis

Density of contents - e.g., drilling mud, produced fluid (oil or gas), seawater, etc.- should be specified for each annulus in a riser system. For example, density of contents should be specified for the primary tube, the annulus line of completion/workover riser, the annulus between the outer/inner casings of a top-tensioned production riser, etc.

Tension applied by each tensioning/compensation system used

- defined as a mean value at a specified location/elevation (e.g., between the tension ring and the TJ Outer Barrel of a drilling riser)- Note that tension displayed on the tensioner panel may be more or less than this value (of mean tension).- Identify if the tension ring is considered as part of the riser system or as part of the tensioners

Vessel heading - typically expressed as relative to North for moored rigs- typically expressed as relative to the direction of the prevailing environment for a dynamically-positioned rigs

Vessel's mean position (or offset) - Mean offset of the vessel is induced by environmental loads and controlled by station-keeping capabilities (e.g., the DP system, the mooring system, or both). For moored rigs, several aspects that should be considered when determining mean vessel offsets include the mooring configuration, directionality of environment, condition of mooring lines (i.e., intact versus failed), use of thruster assist (if applicable), etc. - Note that the rig (or the rotary from which the connected riser is operated) may not always be located directly over the well, even when no environment is present (e.g., intentionally moved to safe zone, etc.).

Low frequency motions - only applicable for moored rigs and may be influenced by thruster assist- account for effects of wind or slow drift (second-order wave motions), if applicable

For selection of vessel RAO information (provided as part of Table A-1) used in analysis

- combination of vessel draft, configuration of mooring lines/risers (for moored rigs), etc.- Select RAO heading based on appropriate combinations of vessel heading and seastate direction

Start date/time for each operation should reflect when riser is first connected to the wellhead systemEnd date/time for each operation should reflects when riser is released from the wellhead systemTimeframe for environmental conditions

- may be selected based on start and end date/time- e.g., annual (Jan.-Dec.), seasonal (Summer only), or monthly (June)

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Table A-17 Listing of information needed to create P-Y curves describing soil properties
Table A-18 Listing of information needed to define weather bins

Detail NotesType/Description e.g., soft clay, stiff clay, sand, etc.Range of applicable depths The depth where each strata begins and ends (below mudline) is needed.

Submerged unit weight applicable to both clays and sandUndrained shear strength for undisturbed soil

- only applicable to clays- For conductor casing that is jetted in, what amount of the undrained shear strength should be assumed during connected riser operations? This may depend on time elapsed since when the conductor casing was initially jetted in.

50% strain to failure only applicable to claysAngle of internal friction only applicable to sand

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Detail NotesProbability of occurrence can also be expressed as number of occurrences or durationSeastate definition - must include wave spectrum shape (e.g., JONSWAP, Torsethaugen, etc.)

and its corresponding details, such as significant wave height (Hs), peak wave period (Tp), etc.

Seastate direction/heading - typically described as towards/from and relative to NorthCurrent profile definition - typically described as towards/from and relative to NorthCurrent profile direction/heading - typically described as towards/from relative to North (at reference

depth)- may vary through the water column

Wind loads - only needed if vessel motions will be determined using a coupled motions model, as opposed to based on vessel RAOs- Static contributions is defined by mean force and mean moment at a specified reference point. - Dynamic contribution is defined by wind spectrum and reference velocity.

Wind direction/heading only needed if vessel motions will be determined using a coupled motions model, as opposed to based on vessel RAOs


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APPENDIX B FLOWCHARTS DESCRIBING EXAMPLES OF
WELLHEAD FATIGUE ANALYSIS METHODS

Figure B-1 Flowchart for example method 1


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Documents

DNVGL-RP-0142 Wellhead fatigue analysis · PDF fileRecommended practice DNVGL-RP-0142 – Edition April 2015 Page 9 ... Specification for Marine Drilling Riser Couplings — API RP