NR 493, Sec 2
2.2
Certificates
2.4
Components of mooring system
2.2.1 Upon satisfactory completion of the installation of
2.4.1
the system and of all activities before, and of related surveys by the Society, the POSA notation is granted and entered in the Initial Hull Classification Certificates of the Unit.
Design specifications and design documentation are to be submitted to the Society for review.
2.3 2.3.1
Design General
In accordance with the provisions of Offshore Rules, Part A, Chapter 1 and Offshore Rules, Part B, Chapter 2, the party applying for classification is to provide the Society with the classification data and assumptions. The design of the mooring system is to be performed on the basis of Unit design data, operational data and environmental data, as specified in Offshore Rules, Part B, Ch 2, Sec 1. 2.3.2
Site Data
As specified for permanent installations in Offshore Rules, Part A, Chapter 1 and Offshore Rules, Part B, Chapter 2, the party applying for classification is to specify the site at which the Unit will operate. 2.3.3
Operating conditions and loads
The manufacturing of materials and sub-components, and the construction of components are to be performed under survey by the Society, according to an approved program. Certificates will be delivered to each set of items, upon satisfactory completion of all related reviews and Surveys. 2.4.2
a) environmental conditions: • extreme environmental conditions (survival condition) • fatigue environmental conditions (operational condition). b) Unit characteristics (the range of loading conditions and associated responses of these Units are to be also specified). c) mooring lines descriptions from anchor to stopper (the mooring lay out is to be also precisely described). d) following loads, in all relevant conditions quoted in b): • environmental loads • anchoring/mooring loads
Load control system
For deep water moorings, taut systems, fibre rope moorings, and other cases where the verification of line pre-tensions cannot be achieved by conventional methods, a permanent load monitoring device is to be fitted on each line, for the control of line pre-tensions at the time of periodical surveys. System may include the transmission of an alarm in case of line failure, or capability for continuous recording over some time, e.g. for re-tensioning operations. Associated computer software is to be in accordance with applicable provisions of NI 425 Recommendations on the Quality of Software On Board (see Sec 1, [1.2.2]).
2.5
The data on Unit operation are to include the following information:
Line components
2.5.1
Survey of installation and deployment Installation on Unit
The installation of Unit-side items (fairleads, stoppers, chainhawses, etc.) and on-board equipment and related systems is to be performed under survey by the Society, in accordance with applicable provisions of Offshore Rules (these activities are to be usually carried out within the frame of Unit Classification Surveys). Survey will cover quality of construction work (particularly through weld Non Destructive Tests - NDT). Load tests are normally not required but, if performed, will be attended. 2.5.2
Deployment at site (installation)
Survey of installation is performed on the basis of general provisions of Offshore Rules, and particularly those of Offshore Rules, Part B, Ch 3, Sec 6. The installation procedures prepared by the relevant Contractor are to be submitted to the Society for examination.
• hawser line loads
Installation tolerances are to be specified in the installation procedures, and duly taken into account in design calculations.
• risers loads • loads induced by other equipments. Note 1: Operational condition is to be understood as usual condition (day to day condition). This notion does not take into account any process or production consideration.
The installation operations will be surveyed, including, but not limited to: • installation of anchors
2.3.4
Methodology
• deployment of mooring lines
The mooring system is to be designed in accordance with the provisions and criteria specified in the present document, where guidance is also given on the methodology for the analysis.
• traceability of components
Statements of design review are issued following the relevant procedures.
• post-installation inspection of the system (by divers and/or ROV Survey).
10
• test loading of anchor and lines (see Sec 3, [10.5]) • connection to Unit and tensioning
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April 2012
NR 493, Sec 2
Reviews and Surveys address only the issues under the scope of Classification, particularly:
3
• conformity of all components to Classification requirements (as attested by Inspection Certificates)
3.1
• integrity of installed parts
3.1.1 The use of ROVs for carrying out the in-water survey
• conformity to design of the system as installed, particularly the setting of line pretensions. Surveys will include attendance of operations at site by the surveyor of the Society, following an agreed program. The surveyor of the Society will review records and other documentation of the installation operations, prior to the delivery of a Certificate. Note 1: Survey by the Society is by no way intended to substitute to Insulator’s duty to fully document installation of the mooring system.
2.6
Documents to be submitted
2.6.1 The Submitted documentation is to include the fol-
lowing information, in addition to what is specified in Offshore Rules, Part A, Chapter 1: a) Design criteria and data, as defined in [2] • Metocean data, soil data, and background information (see Offshore Rules, Part B, Ch 2, Sec 2) • Unit characteristics and range of loading conditions
In service surveys General
is acceptable. The company providing this service will have to be approved as a service supplier for carrying out inwater survey, as per the requirements of IACS UR Z17 (see Sec 1, [1.2.3]). ROV must be equipped in order to produce dimensionally measurement and NDT. ROV capacity should comply with Sec 1, [1.2.5] item m) or equivalent. The surveys of the mooring system of Units granted with additional service feature POSA is normally carried out the Unit being on location, no disruption of Unit's operation being required. For all dimensional check or NDT inspection to be performed by sampling, the number of link surveyed is to be agreed by the Society. For intermediate and renewal surveys, a specific inspection programme is to be submitted to and agreed by the Society, according to the nature and arrangement of the mooring system and other relevant parameters. This programme is to be submitted in written format and agreement signed well in advance of the inspection campaign.
3.2
Annual Survey of anchoring lines
• reports of design analysis.
• layout description including positions of the anchor points, water depth, surrounding equipment (riser, well head, …), layout of other Units in close proximity (see Sec 3, [9.6.1]. • mooring lines description (from anchor to stopper) • location of fairleads and stoppers
c) Structural drawings, specifications and supporting documents: • mooring systems foundations (fairleads, stoppers, winches, bollards, etc.) as applicable.
• connecting systems • ancillary elements • anchoring systems e) Model Tests (when performed) • specification • final report. f) Monitoring and control system • monitoring system description • control system description.
April 2012
3.2.2 The examination of the mooring components (chain
or wire) adjacent to winches or windlasses, stoppers and fairleads is to be performed. 3.2.3 In the case of significant damages revealed by the
• turret structure (if any).
d) Mooring fittings drawings and specifications:
The Surveyor reviews at each annual survey the records of operation of the station keeping equipment and of the examination carried out by the Unit's crew at times of tensioning changes or modifications, if any. 3.2.1
b) General drawings:
above examinations, or if the Surveyor determines that problems have been experienced since last annual survey, a more extensive survey may be required by the Surveyor.
3.3 3.3.1
Intermediate Survey of anchoring lines General
Intermediate survey is usually to be performed two and a half years (21/2) between two renewal surveys. Due to season alternance, tolerance of +/-9 months could be accepted. The overall integrity of the system should be examined, e.g. by general visual inspection of selected lines, over their full lengths, and of all lines in critical areas. Examination of the integrity of critical components with respect to corrosion, wear, overload, fatigue and other possible modes of degradation, by visual inspection and other appropriate methods have to be done. The condition of corrosion protection systems, as applicable, should be verified.
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NR 493, Sec 2
Pretension setting of each line (or angle measurement) should be confirmed.
3.4
Additional inspections/tests in accordance with the specific inspection program could also be performed.
3.4.1
3.3.2
Global anchoring line
Class Renewal Surveys of anchoring lines General
At renewal survey (every five years), the overall integrity of the system should be examined, e.g. by general visual inspection of all lines, over their full lengths (by ROV or divers).
The Surveyor reviews the records of operation of the station keeping equipment and of the examination carried out by the Unit’s crew at times of handling, if any.
Examination of the integrity of critical components with respect to corrosion, wear, overload, fatigue and other possible modes of degradation, by visual inspection and other appropriate methods has to be done.
3.3.3
The condition of corrosion protection systems, as applicable, should be verified.
Connection with the stopper
As far as practicable, visual inspection has to be performed for links the closest to the stopper, in all lines. This requirement could be mitigated in case of difficulty to access this part of the chain (e.g. bell hawse stopper).
Confirmation of the pretension setting of each line (or angle measurement) should be confirmed.
3.3.4
3.4.2
Above water chain segment
For Units having fairleads or stoppers above water level, the following should be verified: • Visual examination of the whole length of the mooring line above water for all lines • Dimensional checks of at least one link in the last 5 meters of chains above water in all lines (two measurements per link is deemed sufficient). • Additional dimensional checks of sample of links of this portion in all lines • Measurement of chain angle (or tension) at top. 3.3.5
Upper line segment
• Visual examination of the 10 first meters of chain underwater for all lines • For chains, dimensional checks of a sample of links of the 10 first meters of this portion, in a representative number of lines (at least one per bundle in case of bundle configuration). Specific provisions applicable to Fibre Rope mooring lines are given in NI432 (See Sec 1, [1.2.2]). Bottom line segment
For all types of anchoring systems, the following inspections should be performed:
Global anchoring line
Special survey at the fifth year (first term), tenth, fifteenth, twentieth year and subsequently (other terms) if satisfactory extra margin of corrosion is considered. The Surveyor reviews at each annual survey the records of operation of the station keeping equipment and of the examination carried out by the Unit's crew at times of tensioning changes or modifications, if any. 3.4.3
Connection with the stopper
As far as practicable, inspection, dimensional check and NDT inspection has to be performed for links connected to the stopper, in all lines. 3.4.4
For all types of anchoring systems, the following inspections should be performed:
3.3.6
Additional inspections/tests in accordance with the specific inspection program is also be performed.
Above water chain segment
For Units having fairleads or stoppers above water level, the following items should be verified: • Visual inspection of the stopper adjacent portion • Dimensional checks of all links of this portion in all lines • Measurement of chain angle (or tension) at top. 3.4.5
Upper line segment (first 10 meters of underwater chain)
In all lines of the mooring system, following inspections should be performed: • Visual inspection of the stopper adjacent portion (in case of underwear stopper) • Dimensional checks of this portion • Measurement of chain angle (or tension) at top (in case of underwater stopper). These items should be covered with a Unit at minimum draft. 3.4.6
Wire rope
• Examination by divers or ROV of a representative chain length close to the contact with seabed for all lines.
In case of sheating, visual inspection should be performed for all lines all along the wire rope segments.
3.3.7
In case wire is not sheated, diameter measurement should be performed for all lines all along the wire rope segments.
Jewellery
A general examination of all jewelleries (socket, shackle,...) is to be performed for a representative number of lines. Refer to Sec 4 for additional information.
12
3.4.7
Fibre rope
Specific provisions applicable to Fibre Rope mooring lines are given in NI 432 (Cf. Sec 1, [1.2.2]).
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April 2012
NR 493, Sec 2
3.4.8
Anchors and buried chains
For anchors and buried chains, the following inspections should be performed: • Visual inspection of the soil around the anchors, in particular to check the absence of scouring in the vicinity of anchors • Buried part of the chain and the connection with anchors being generally not inspectable, examination of operations logs has to be done to confirm that each leg was recently subject to a significant loading giving indications that the segment has not failed. Note 1: In addition to that, IACS Rec. 38 (See Sec 1, [1.2.4]) should be applied.
3.4.9
Jewellery
All jewelleries (socket, shackle,...) should be visually inspected for all lines. Confer to Sec 4 for additional information.
3.5
Survey summary
3.5.1
As a rule, for studless or studlink chains, a link should be considered as defective if one of the following criteria is not satisfied: 3.6.2
• the average of the two measured diameters (90 degrees apart) is to be more than 95% of the as-built diameter • diameter in any direction is to be more than 90% of the as-built diameter The final criteria to replace chains is linked to initial computation hypotheses (mainly hypothesis on wear and corrosion during design of mooring system). 3.6.3 In the case of mooring system designed taking into
account a corrosion margin, the following criteria should be fulfilled: the lowest measured diameter Dm should be higher than the as-built diameter D reduced by the total design corrosion margin C (annual corrosion rate times the initial design life) • Dm > 95%(D - C) 3.6.4 At least one measurement at the interlink (See Fig 1)
and one in an other location visually judged as the worst should be performed. For criteria at interlink, consideration on fabrication tolerance should be given.
Intermediate and renewal surveys
Figure 2 : Interlink measurement
Fig 2 summarises the intermediate and renewal surveys to be performed along the anchoring lines.
3.6
Interlink
Renewal criteria for chains, steel wire ropes and fibre ropes of permanent installations
For all the following paragraphs, measurement should be performed after cleaning of the marine growth. 3.6.1
Figure 1 : Survey summary
3.6.5 In case criterion in [3.6.3] is not fulfilled and in order
to avoid to replace a defective segment, the following analyses should be provided for review: • Anchoring lines extreme tensions analysis
I&R I&R
• Anchoring lines fatigue analysis
10 m
• Strength analysis of link.
R
10 m
Analyses should account for the observed diameter and a provision of expected corrosion/wear for the five (5) following years, in line with rates previously observed.
I&R
Strength analysis aims at providing information on the residual resistance of the corroded/weared link and is to be performed following Sec 3, [8.2]. In case the corrosion and wear of a link is higher than the value defined during the mooring system design (end of design life), following considerations apply:
I&R
10 m
R I&R
10 m
I
:
Intermediate survey
R
:
Renewal survey
April 2012
• as a rule, the theoretical minimum breaking strength of an equivalent "as-built" link of the reduced diameter (Dm-corrosion) cannot be taken into account • special consideration may be given in case of appropriate documentation of the remaining resistance of the chain (based on actual corroded link dimensions).
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NR 493, Sec 2
3.6.6 For studlink chain, if a stud is missing, the link is con-
sidered as defective. 3.6.7 Replacement of a link considered as defective is to be
based on a plan subject to Society approval.
14
Damage on the core of the wire rope or on the sheathing should be analysed on a case by case basis (See API RP 2I Sec 1, [1.2.5]for criteria). 3.6.8
Note 1: For the purpose of [3.6], it could be referred to API RP 2I (See Sec 1, [1.2.5]).
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April 2012
NR 493, Sec 3
SECTION 3
DESIGN OF MOORING SYSTEM
Symbols TP
: Peak period of the wave spectrum, in s
Tz
: Zero-up crossing period of the wave spectrum, in s
T0
: Largest natural period of the system for motions in the horizontal plane, in s
nf
: Number of elementary Airy wave components.
1 1.1
Methods of evaluation
2.1
Subject
requirements related to the design of a mooring system, with a view to the assignment of the notation POSA to a floating offshore unit. The present Section includes:
Objective
2.1.1 The objective of analysis is to obtain information on
Unit motions, the resulting excursions and line tensions, under some specified metocean conditions, that are representative of: • either the extreme conditions at intended site, or some limit operating conditions, for the evaluation of design (extreme) values
• guidance methodology for mooring analysis • design criteria. Alternative methodologies will be given consideration, on a case by case basis, provided they are demonstrated to provide a Safety Level equivalent to that resulting from the application of the present document. Note 1: Unless otherwise specified, documents quoted in Sec 1, [1.2.5] are for general reference and may complement, but not replace, the requirements of the present document.
• or more frequently occurring conditions, for the assessment of fatigue. 2.1.2
Available methods
The available methods of analysis vary by the approach taken to evaluate: • overall system response and resulting excursions and Unit motions
Review of design
1.2.1 For the granting of the notation POSA, the proposed
design and supporting documentation are reviewed, including documents in Sec 2, [2.6.1]. Verification is generally performed by independent analysis, following the methodology of this document. Note 1: Independent analysis is by no way intended to substitute to designer's duty to fully document his des ign.
1.3
Additional considerations for the integrity of the lines are also to be considered (contact of connectors with soil, uplift at anchor, clashing, synthetic rope minimum tension …). All these items are covered in this note.
2
General
1.1.1 The purpose of the present Section is to provide Class
1.2
Global line should be assessed for strength (intact, damaged and transient) and fatigue (TT and OPB/IPB) purposes.
General methodology
• line response and resulting tensions. Model Tests are another possible source of information, as discussed below. Guidance and criteria in the present document are made with reference to the Quasi-dynamic and the Quasidynamic/Dynamic line response methods, as defined below.
2.2
Quasi-static analysis
1.3.1 Mooring lines POSA assessment should cover follow-
ing items:
2.2.1 In a quasi-static analysis, the line tensions are evalu-
• Global lines
ated from the static line response to loads/displacements that are applied on Unit as static actions.
• Mooring components • Fairleads / Stoppers • Anchors.
April 2012
This method is often used at an initial planning stage, but is not deemed acceptable for system design nor for Class assessment.
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NR 493, Sec 3
2.3 2.3.1
Quasi-dynamic analysis Methodology
A methodology for analysis of mooring systems, the “Quasidynamic analysis”, has been developed by the Society, and presented in a) of Sec 1, [1.3] and [3.3]. This method is generally considered as the most adequate for moorings in shallow and moderate water depths, in the conditions specified in [2.3.2]and [5.3]. Background information is presented in reference b) of Sec 1, [1.3]. 2.3.2
Model tests however will not be generally deemed sufficient to fully document a design, due to practical limitations in the modelling of the system (e.g. with respect to water depth), and in the number of system configurations and combinations of metocean parameters that can be addressed within a testing program. Note 1: These tests are considered as a source of information for design and do not form part of physical testing activities during manufacturing and construction.
3
Environment, actions and motions
3.1
Limitations of the calculation methodology
The mooring system is assumed not to be subject to resonance at the wave frequency. In addition, out-of-horizontalplane low frequency motions are supposed to be negligible. Hence, this methodology may not be appropriate to Spars or certain types of semi-submersibles operating at very large drafts. It is supposed that horizontal low and wave frequency phenomena do not interfere. Compliance with this assumption is reasonably satisfied if the natural period of the mooring system in surge, sway and yaw is greater than five times the zero-up crossing period of the wave. The variation of the suspended line weight with the motion of the moored Unit is supposed not to significantly modify the average Unit draft, trim or list angles.
3.1.1
E nvironment Waves
Waves are defined by the parameters of a wave energy spectrum. In some areas, it will be relevant to split the incoming energy in two (or more) parts (e.g. swell and wind sea), modelled by two (or more) spectra with different directions of approach. For modelling of waves by elementary Airy wave components, using the technique of random frequency and random phase, the number nf of elementary Airy wave components (in each spectrum) is not to be taken less than: nf ≥ 100 not less than: n f ≥ 30 ⋅ T0 ⁄ T p
2.4
Dynamic line response
2.4.1 In a Dynamic line response analysis, the dynamic Unit
response is computed by the same method as in Quasidynamic analysis, but the line tensions are evaluated from a Dynamic analysis of the line response to the fairlead motion. This method is applicable to deep water moorings, or very harsh metocean conditions, where the criteria of acceptability of Quasi-dynamic analysis are not met, and, in all cases, to fatigue analysis.
provided the range of circular frequency ( ∆ω = ω M − ω m, with ω M and ω m - the Maximum and minimum circular frequency for wind spectrum, in Hz) does not exceed 15/T p (otherwise, nf is to be increased accordingly). 3.1.2
Wind
A description by a constant speed V 10-min (without wind spectrum) may be used for initial evaluations or when the natural period T0 is not very large. In case of lower T 0, V1-min shall be considered.
2.5
Other methods of analysis
2.5.1 Fully coupled analysis might be used when couplings
are deemed important, or for calibration purpose.
2.6
In the discretisation of spectrum, the minimum frequency, in Hz, is not to be taken less than the frequency corresponding to a 1 h period, i.e.:
Model tests
2.6.1 As a rule, tunnel (or basin) tests are to be performed
in order to obtain load coefficients for wind and current on the Unit. As a rule, model tests in the basin are to be carried out for the validation of the overall behavior of the system and the calibration of analyses. Consideration may be given, on a case by case basis, to model tests performed on a very similar system, in equivalent metocean conditions and water depth.
16
Otherwise, e.g. in deep waters, a description by an appropriate wind spectrum combined with a wind speed V 1-hour should be used.
f m = 2,8 10-4 The upper frequency f M may be taken in the range of 0,03 to 0,05 Hz. However, a higher frequency content is to be taken into account if the smallest natural period of the system (for horizontal motions) is lower than 1 mn. Number of frequencies is to be selected so that the frequency interval ∆f satisfy: ∆f < 0,1 / T0 and ∆f < f m
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NR 493, Sec 3
3.1.3
Squalls
3.2.2
Strong and sudden winds (squalls) occurring in inter tropical convergence zone (ITCZ) are to be modelled by representative time series of wind speed and direction. As a rule, the calculation methodology should follow the steps below:
a) Load coefficients for wind and current loads are to be obtained from tunnel (or basin) tests. Consideration will be given to derivation of data from tests on a very similar model. In such tests a model is maintained in a turbulent flow of adequate intensity and profile, in a fixed position, with a given incidence. The loads thus measured are projected on the Unit axes:
a) A set of squalls is defined for the considered site. Squalls are rescaled as per App 2, [2.4.2]. b) Each squall is considered as a governing element and so combined with wave(s) and current in accordance with App 2, [5] and metocean specification. Directional scanning interval and scanning methodology shall follow App 2, [3].
Fx=Cx(θ).V2 Fy=Cy(θ).V2 Mψ =Cψ (θ).V2 Where:
c) Design response (of tension, offset,...) is the maximum responses obtained over all the squall cases except otherwise agreed. Note 1: This methodology is based on the present knowledge about squalls.
Note 4: Additional information about squalls can be found in Sec 1, [1.3], k).
3.1.4
Some approximations can be used in given cases. The most popular one is the Newman’s approximation. Newman's variants Molin or BV are largely used in practice. Both are valid for deep water and also soft mooring systems, but invalid for stiff mooring systems and in shallow water.
: Yaw moment : Flow (reference) velocity and incidence.
At initial design stage, load coefficients may be obtained from analytical expressions (e.g. extended Duchemin Formula) or other heuristic expression, provided all three components of force are taken into account (reduction to the in-line component is not considered adequate in this respect). b) Wind Load Wind loads are evaluated by the above formulae, taking into account the wind speed at a reference elevation (typically 10 m above sea level - same as in tests), and the incidence of wind with respect to vessel. c) Current Load
Another approach called BV approximation allows dealing with soft mooring system in shallow or deep water. The most general way to reconstruct the 2nd order loads in time domain is to use the full QTF matrix (See papers c) and d) quoted in Sec 1, [1.3]). The low-frequency wave loading is computed by a double summation (QTFC -complete - formulation). This requires the full QTF matrix determination and can induce large computing time. Consideration should be given to the use of this “full QTF”, in the case where the Newman approximation might not be sufficient (as a guidance: when slow drift natural period is less than 150 s, or in water depth less than 40m).
April 2012
Mψ
Note 2: These data are relevant for tankers or LNG Carriers, and not applicable to different hull shapes or arrangement of superstructure.
Wave drift load
Quadratic Transfer Functions (QTF) are the second order low-frequency wave loads for floating body.
: Force along vessel transverse horizontal axis
When applicable, the data in “Prediction of Wind and Current Loads on VLCC's, Oil Companies International Marine Forum” Sec 1, [1.2.5]) and “Prediction of Wind Loads on Large Liquefied Gas Carriers” Sec 1, [1.2.5]) can be used for tanker shaped units.
Actions
3.2.1
Fy
Note 1: Concerning yaw moment, particular attention should be paid to the reference point where the moments are calculated (origin O of the Unit axis system, Unit centre of gravity G, midship section, etc.).
A description of near-surface current by a constant speed is normally sufficient (cf. App 2).
3.2
: Force along vessel longitudinal axis
V, θ
Current
Sudden changes (local surface currents, loop currents) occurring in some areas may induce significant transient effects and are to be modelled by representative time series of current intensity and direction.
Fx
Cx, Cy, Cψ : Corresponding force coefficients
Note 2: When no time serie is available, using a constant wind is not sufficient to assess squalls. Note 3: Scanning methodology with an optimized step b) could be send to Class for agreement on a case by case basis
Wind and current loads
Bureau Veritas
1) As the vessel is moving in water, the instantaneous loads (combining current load and drag induced by motions) are evaluated by the above formulae, taking into account the equivalent incidence αc and the equivalent current velocity Uc as follows. Given Vc and βc-Ψ the current velocity and incidence (incoming direction w.r.t. vessel), the equivalent current intensity U c and relative incidence αc are given by: ·
Uc
=
Vc + V
where V is the vector of vessel intant velocity.
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NR 493, Sec 3
2) When the Unit is fixed during current model tests, the force coefficient Cψ does not include any effect due to the rotation of the Unit in the fluid. In such case, the Molin’s yaw moment (only valid for barge or shipshape units) is therefore to be added to that derived from model tests. Additional information can be found in Sec 1, [1.3], h).
FBx=-Bxxu FBy=-Byyv ·
M B Ψ ⁄ o
Riser loads
Risers and other fluid carrying lines (e.g. an export line) are generally kept under tension (possibly resulting in permanent pull on the Unit), and are subject to the action of current over the water column. The resulting forces may represent a significant part of the total load on the Unit. The reactions on Unit may be obtained from a static analysis of the lines.
• either a static load, corresponding to a mean offset condition, and dummy lines to represent variations of load around this position, or
-
u
: Absolute velocity in surge of the origin O of the Unit axis system
v
: Absolute velocity in sway of the origin O of the Unit axis system
Ψ
: Function versus time of the Unit heading
Bxx
: Linear damping coefficient in surge
Byy
: Linear damping coefficient in sway
Bψψ
: Linear damping coefficient in yaw.
F
: Force induced by damping.
M
: Moment induced by damipng.
c) Data in Tab 1 could be used as a preliminary approach, unless more accurate data is available from model test, or fully coupled analysis calibrated by model tests, to assist in the calibration of the slow-drift damping coefficients. These data applies only for usual mooring systems. For Unit moored by only surface lines, as a Unit on a single point mooring or a shuttle tanker moored to a FPSO, the values from formula in Tab 1 for tanker should be multiplied by a factor 0,37.
Damping
a) The sources of damping on a moored Unit are multiple and of various nature. Different theories exist to explain and model these effects. However, all of them are based on either fully empirical or semi-analytical formulations the range of validity of which is necessarily limited.
d) A direct assessment of damping terms requires that main contributing terms are separately evaluated:
Any damping model requires to be calibrated and its field of applicability clearly identified. Limitations of the present approach are specified in [2.3.2]. Damping due to hull drag is modelled together with current loads since these loads are calculated on the basis of the relative fluid velocity (see [3.2.2]). Other sources of damping can be modelled by a linear dampins, i.e. forces proportional to the absolute speed of the Unit, according to the following formulae:
18
d ψ dt
The values proposed in Tab 1 tentatively account for most of sources of damping (see d) below) [3.2.2].
• tabulated loads, for a range of positions around the expected mean position (see ref. 4 in paper b) quoted in Sec 1, [1.3]). 3.2.4
B ΨΨ
b) The result of the simulation are quite sensitive to the linear damping coefficients. Great care must therefore be paid to their evaluation.
Attention should be given to the effect of varying direction and intensity of current along the water column. The mean static load, that is depending upon the instantaneous low frequency position of the Unit, may be modelled by:
–
where:
Note 3: With the above relative velocity formulation and the equations of motions expressed in vessel axis, the hydrodynamic yaw moment includes a steady component: the Munk moment. As this moment is already included in the moment calculated from current forces coefficients, it should be substracted in the load balance.
3.2.3
=
Bureau Veritas
• viscous damping on the hull is accounted for by the relative velocity formulation of the equations of manoeuvrability • wave drift damping may be obtained from the drift forces and its derivates. Reference can be made to the formulation in papers f) and g) of Sec 1, [1.3]. In these papers the quadratic transfer function matrix is modified taking into account the slow drift velocity, the current speed and the instantaneous heading • damping due to lines (risers and mooring lines) may be estimated from line Dynamic calculations, or inferred from a fully coupled analysis • bottom friction effects on mooring lines.
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NR 493, Sec 3
Table 1 : Low-band linear damping coefficients for different types of usual mooring systems
Mooring system Barge or tanker in spread mooring Barge or tanker on a SPM (1) Semi-submersible Unit at operating draft (1)
Bxx
Byy
0, 06 K Ox x ( m + Ma xx )
0, 06 K Oy y ( m + Ma yy )
0, 01m g-L
0, 02m -g-B
0, 20 KOx x ( m + Ma xx )
0, 20 KOy y ( m + Ma yy )
Bψψ 0, 10 K O ΨΨ [ I ΨΨ
+
Ma ΨΨ
+
2
( m + Ma yy ) x G ]
0,083 L 2 Byy 0, 10 K O ΨΨ [ I ΨΨ
+
Ma ΨΨ
+
2
( m + Ma yy ) x G ]
The values of B xx, Byy and Bψψ are given assuming that the origin O of the ship axis system is in the midship section.
Note 1:
KOxx, KOyy, KOψψ : Diagonal terms of the mooring stiffness matrix [K O], evaluated at the average position of the Unit d uring the storm Maxx, Mayy, Maψψ : Diagonal terms of the asymptotic added mass matrix of the Unit Iψψ : Moment of inertia in yaw, in kg⋅m2, calculated at the centre of gravity G of the Unit m : Mass of the Unit, in kg L : Length of the Unit, in m B : Breadth of the Unit, in m. Note 2: For spread mooring, B xx and Byy correspond to 3% of the critical damping and B ψψ to 5% of the critical damping.
3.2.5
Other loads
Thrusters are sometimes used to assist a passive mooring system. The driving system of the thruster loads may be very simple (e.g. constant load in a constant direction relative to the Unit heading) or more complex. Note 1: See ISO Sec 1, [1.2.5], k).
In any case, the loads that the thrusters actually produce on the moored Unit should be computed at each time step as a function of the applicable parameters. Recognised methods should be used for the load calculations, with due account for possible interferences between the thrusters themselves or between the thrusters and the hull and for all other phenomena that may modify, alter or degrade the thruster performances.
3.3
expressed typically in a system of axis linked to the Unit), for predefined time series of wave elevation and other parameters. This is made taking into account the actions of waves, wind,... as detailed in [3.2] above, all evaluated taken into account the instant of low-frequency position and the relative heading of the vessel with respect to each action, and: • the restoring mooring force (see [4.2] below) • the mass matrix and added mass of the Unit (added mass calculated for ω -> 0) • a linear damping as per [3.2.4] above. 3.3.3
a) Unit motions (RAO’s) As as a pre-requisite to mooring analysis, the six motions of the vessel in the frequency domain (RAO’s) should be determined.
Unit response
3.3.1
General
In a Quasi-dynamic analysis, the dynamic Unit response is computed using a mixed time-domain/frequency domain analysis, taking into account quasi-static line response. The calculation procedure consists of the determination of the low frequency response of the moored Unit under the effect of waves, wind and current, by time domain simulations, followed by the superimposition of the wave frequency motions. It is assumed that low and wave frequency components do not significantly interfere with each other because of very different time scales (see [2.3.2]). As a consequence, they are assessed separately in the framework of this approximation and added together at the end of each time step of the simulation. At the end of each time step, the line tensions are evaluated from the quasi-static line response to the fairlead motion. 3.3.2
Low Frequency response
The mean and low-frequency responses (three motions) of the Unit in the horizontal plane are calculated by resolving, in a time domain simulation, the equations of the dynamic equilibrium of the Unit (equation of manoeuvrability,
April 2012
Wave Frequency motions
Bureau Veritas
The RAO's can be obtained by model tests or by a recognised first order diffraction-radiation analysis program, with due account for the actual site water depth. It is assumed that the wave frequency motions of the Unit are not significantly disturbed by the variation of the mooring stiffness with the low frequency offset. An average mooring stiffness can therefore be used for predetermining the Response Amplitude Operators (RAO's) of the Unit. In motion analysis, account may be taken of hydrodynamic damping on the floating body, (e.g. roll damping), by appropriate formulation. The effect of suspended load of the mooring lines and of risers (vertical and horizontal components), around the mean Unit position, should be accounted for, not as mass, but as terms in the stiffness matrix, together with the stiffness of these systems. Additional wave frequency dynamic effects of lines (primarily damping) might be significant in some cases, and may be estimated from line Dynamic calculations, or inferred from a fully coupled analysis.
19
NR 493, Sec 3
b) Wave frequency motions The wave frequency motions are obtained by linear summation of those due to each component of the waves, taking into account the instant low-frequency position and the relative heading of the vessel with respect to waves. At each time step of the simulation, the six wave frequency motions are superposed to the low frequency motions, to get the instant position of the vessel, thus the position of each fairlead from which the line response (see [5]) can be evaluated.
4
Mooring System
4.1
Mooring pattern and initial tensions
4.1.1 The mooring pattern is the theoretical description of
the mooring system as installed on site. The mooring pattern thus includes the general layout of the mooring system and the elevation of each line in its initial vertical plane. To achieve such a description, the following information is needed: • Site bathymetry • Unit position and heading
Mooring response
4.2.1 Following the assumptions in [5.1.1] below, the load
induced by any mooring line on the moored Unit depends only on the anchor-to-fairlead distance. The azimuth of a mooring line is defined by the relative position of fairlead and anchor. In the time domain simulation of low frequency motion, the mooring restoring force (horizontal force and yaw moment) at each time step is obtained by summation of the horizontal components of line tensions at each fairlead, as resulting from fairlead position under the low frequency motion.
4.3
Mooring stiffness
elementary external loads applied to the Unit with its resulting elementary displacements around a given position. The mooring stiffness is to be considered for the calculation of unit motions RAO’s. In most cases, the stiffness induced by the mooring system for out-of-horizontal plane motions is negligible in comparison with the hydrostatic stiffness.
• Anchor positions • Mooring line composition • Paid-out line lengths. 4.1.2 The knowledge of all items listed in [4.1.1] automati-
cally settles the initial tensions since a relation of the following form exists for each line as soon as its vertical plane is known: =
4.2
4.3.1 The mooring stiffness is the 6-by-6 matrix which links
• Unit draft and vertical centre of gravity • Fairlead positions
f ( L, D, T )
In practice, an iterative process is needed to set the initial tensions to their prescribed values, and to ensure that the three parameters are compatible together.
0
The sensitivity to input is illustrated in Fig 1(example of unit surge motion). 4.3.2 The stiffness matrix [K] is obtained by the summation
of the contributions of all mooring lines under six elementary displacement of the vessel.
where: L
: Paid-out length of the line
D
: Horizontal distance between the anchor and the fairlead
T
: Tension at fairlead.
Note 1: The stiffness matrix can be also obtained by multi-linear regression, versus the time series of vessel motions, of a time series of the mooring force, computed after an analysis taking into account both low- frequency a nd wave frequency motions.
Figure 1 : Effect of mooring stiffness on RAO 2,0 1,8 1,6 ) 1,4 m / 1,2 m ( n 1,0 o i t 0,8 o M0,6
Increasing mooring stiffness
0,4 0,2 0,0 0,2
0,4
0,6
0,8
1,0
1,2
1,4
Wave circular frequency (rad/s)
20
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April 2012
NR 493, Sec 3
5
Line response
Thus α is given by: α = 1 / (Kr * MBS)
5.1
Quasi-static line response
5.1.1
Note 1: A polynomial fit of the break load test load-elongation curve is not appropriate in this case.
Assumptions
The lower end of the mooring line is anchored to a fixed point. The upper end is connected to a fairlead of the moored Unit which can be either emerging or immersed. The mooring line cannot penetrate the seabed. The mooring line is made up of a series of homogeneous segments attached end-to-end, the bending stiffness of which is negligible. A homogeneous segment is characterised by constant mechanical properties over its whole length. A buoy or a sinker may be connected at the upper end of any segment. At any time, the mooring line is assumed to be in the vertical plane passing by its anchoring point and its fairlead. This implies that wave, current, wind and dynamic loads on any of the mooring line components are neglected. It also implies that friction effects, transverse to those parts of the line laying on the seabed, are not taken into account. 5.1.2
Line elements
The quasi-static line response is based on the equations of the elastic catenary. For chains and wire ropes, the elastic response is linear. This write: dl ----l
=
4 2 π Eφ
Manufacturer’s data (usually presented as a curve giving the tension in percent of the breaking load (BL) versus the relative elongation of the material) may be converted in a relation as in [5.1.2] above 5.1.6
Buoys and sinker should be carefully modelled so that the net action that they exert to the mooring line remains correct whatever the tension in the line and the resulting position of the element with respect to sea level or seabed.
element model of the line. a) Hydrodynamic drag coefficient CD and inertia coefficient CA may be taken as shown in Tab 3. CD, respectively CA, is given based on the reference diameter, respectively volume per unit length, of a rod with the effective diameter Deff based on: • nominal chain diameter d, for chains
For some other materials (e.g. some synthetic material see [5.1.6]) the relation dl/l=f(T) is not linear: it can be approximated e.g. by a polynomial function of the tension.
Wire ropes
Dynamic line analysis
5.2.1 The Dynamic line response is obtained from a finite
in which φ is the nominal diameter of the chain or wire rope and E the equivalent Young modulus.
5.1.3
Buoys and sinkers
A buoy (respectively a sinker) induces an upward (respectively downward) load to the point of the line to which it is attached.
= ------------
The elasticity properties of different materials are given in [5.1.4] to [5.1.6].
Hawsers
Hawsers and other fibre ropes are generally substantially more compliant than deep water mooring ropes. In the absence of better data, the load-elongation curve corresponding to a worked rope of the same material and construction may be used, but may still over-predict mean offset and under-predict maximum load. Data taken from a new rope (first extension) are not acceptable.
5.2
αT
Where dl is the elongation of an elementary length l of the line at rest, when submitted to a tension T at both ends, and α is given by: α2
5.1.5
• rope outside diameter D, for wire rope and fibre rope. Note 1: The force coefficient CM N = 1 + CA N is also used to specify the normal coefficient.
b) Length of elements i in finite element model should not exceed, for each segment of line:
Specific data are to be obtained from the manufacturer since the stiffness properties depend upon the wire rope design.
i =
TP
F mean -----------m Ni
where: 5.1.4
Fibre rope mooring lines
mNi
A model for the load-elongation characteristics of polyester deep water mooring lines is given in NI432 (See Sec 1, [1.2.2] and Sec 1, [1.3]).
mN may be obtained from Tab 3 based on the (in air) mass per unit length m of the line segment
The equivalent linear elastic properties are there expressed as a non-dimensional stiffness: Kr = ( ∆T/MBS) / (dl / l) where MBS is the breaking strength of the line.
April 2012
: Total transversal (normal) mass per unit length of the line segment, in water, in kg/m.
Fmean
: Mean line tension, in kN.
Note 2: A smaller length of elements is generally necessary in the touchdown area.
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21
NR 493, Sec 3
6
Table 2 : Hydrodynamic coefficients
Deff Chain
1,8 d
Wire rope Fibre rope (2) (1) (2) (3)
D
CDN
CAN
CAL
(1) (3)
(1)
(1)
0,8
1
0,5
1,13 m
6.1.1 For any sea-state to be considered, n simulations of at
1
0
1,20 m
1,1
0,15
2,00 m
least three hours each should be performed using different sets of elementary waves representative of the whole spectrum. If a wind gust spectrum is used, the same provision applies.
0,7
6.1
mN
Suffix N is for Normal (transversal) direction Suffix L is for Longitudinal (tangential) direction For fibre rope, CA N and CA L are inclusive of entrapped water. CDN are specified as lower bound, to avoid unconservative over-estimate of damping effects.
5.2.2 The mean position is set to get the mean tension F mean
from the Unit response analysis, and the 3D fairlead motion is applied as an imposed displacement at the top of the line. Current and time depending water particle kinematics are also applied, but this latter term gives a marginal contribution and can be neglected. 5.2.3 Time domain analysis involves iterations at each time
step, and the iteration parameters (particularly the maximum number of iterations) must be set so as to get an unspoiled solution.
5.3
Intact condition
Note 1: For squalls analysis, duration of the si mulation will depend on squall time serie record. Note 2: Guidances for me tocean combinations are given in App 2
The response signals should be built up with a time step equal to or less than one tenth of the peak or zero-up crossing period of the wave spectrum, whichever is the most appropriate. The design tension of a line in intact condition, for a specified set of Unit and metocean conditions, is defined from the mean and the standard deviation of the n maxima T k, each obtained from n simulations, using different “seeds”, i.e. different sets of elementary waves and wind components. The maxima are either the maxima of the Quasi-dynamic tension, or the maxima of the Dynamic tension, obtained as defined in [5.4] above. The design load T D for the condition analysed is given by: TD = TM + a TS
Characterization of the line response
where:
When the Quasi-dynamic line response has been obtained, a test-run of Dynamic response is to be performed, in order to characterize the Dynamic response, and evaluate, or confirm, if the Quasi-dynamic response can be used for the evaluation of extreme loads. 5.3.1
• TM is the mean of T k : TM
Such evaluation may be omitted for chain moorings in moderate water depths (less than 150 m), if all the other conditions specified in [2] are met, and accordingly the safety factors for Quasi-dynamic analysis are used.
1 n
= --
Tk
• TS is the (n − 1) standard deviation, given by: T 2S
Details of methodology and criteria for this evaluation are given in App 1.
5.4
Design tensions
1 n 1
= -----------–
(Tk – TM )
• a is a factor, given in Tab 4, as a function of the type of analysis actually performed, and the number of simulations Table 3 : Factor “a”
Dynamic line response
Method of analysis
5.4.1 For a given simulation, the maximum tension over
the duration of the simulation (at least three hours) is to be obtained. This can be achieved by performing Dynamic analyses over a limited number of windows, each with a duration not less than T0, the natural period of Unit low frequency motion. Three to five windows are to be selected, based on the maxima of dTqd / dt, or of Tqd if relevant (see App 1).
2
Number of simulations n 5
10
20
≥ 30
Dynamic
0,60
0,30
0,10
0
Dynamic − 1 window
1,20
0,80
0,55
0,45
Quasi-dynamic
1,80
0,90
0,50
0,40
Note 1: For
intermediate numbers, a can be obtained by interpolation with n
6.2
One-line damaged condition
Alternatively, when the correlation of T dyn with dTqd / dt is clearly established, an option is to analyse only one window corresponding to the expected maximum.
6.2.1 The design tension of a line in damaged condition is
The maximum tension for the simulation is then taken as the maximum over the several windows, or the maximum in the selected one-window, as relevant.
Note 1: The failure of an ancillary line component (buoy or sinker, etc.) is also a damaged condition. However in most cases such condition is covered by the above analysis.
5.4.2
22
obtained by the same method as the “intact” tension, considering a system with any one line removed, or a thruster failure as specified in [6.5].
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April 2012
NR 493, Sec 3
6.3
One-line failure (transient) condition
for all five simulations. For this particular one-line-failure case, the tension in damage condition of each remaining line is the average of its five maxima thus obtained.
6.3.1 The design tension of a line in a failure (transient)
condition is obtained as the average over a set of possible failure instants, of the maximum transient tension (see also [9.6]). The procedure described in a) and b) should be repeated for each line: a) For the sea-state to be considered and for each mooring line, the simulation to be selected for the study of the one-line failure case should satisfy the following criteria: • the maximum fairlead tension is the closest to its design tension in intact condition as defined in [6.1.1], and • this maximum occurs while the low frequency component of the tension is increasing. If the second criterion is not met, the selection procedure should be resumed with the highest second maximum in the same simulation or the closest second simulation. The two instants around the maximum tension where the low frequency component of the tension is respectively minimum and maximum should be identified. See Fig 2. b) Using always the same sets of Airy waves and wind components as those used in the simulation identified in a), five simulations are repeated; during these simulations, the line should be broken at different times equally distributed between the two instants identified in a) with the objective of catching maximum. All five simulations should be run from the beginning in order to ensure the same initial numerical transient. They can be terminated after two low frequency cycles following the line failure. The maximum tension obtained at the fairlead of each remaining line after the line failure should be identified
c) For a given line, the design tension in damage condition is the maximum of all possible one-line failure cases.
6.4
Two-lines damaged condition
6.4.1 Residual strength based on a system with two lines
removed has to be estimated. The design tension of a line in two-lines damaged condition is obtained by the same method as the “intact” tension, considering a system with two adjacent lines removed This criteria is only part of the POSA-HR notation and is not requested for POSA notation.
6.5
Thruster failure
6.5.1 The thruster failure is assumed not to be concomitant
with a mooring line failure. 6.5.2 Two kinds of failure should be investigated:
a) the total loss of one thruster, the other thrusters having two thirds of their maximum thrust capacity available, b) loss of half the total thrust capacity. Note 1: These two cases lead to the same remaining thrust capacity for a unit equipped with four identical thrusters.
6.5.3 The design tensions in the mooring lines should be
determined by a method similar to that described in [6.1] for the one-line failure case. The instants of failure, however, can be randomly selected during the simulation identified in [6.3.1] with a sufficient number to ensure that the statistics derived from the response samples are reasonably representative.
Figure 2 : Range of time to be selected for the one-line failure case
Tension (kN) Maximum tension in intact condition
2750 2700 2650 2600 2550 2500 2450 2400 2350 2300 2250
Time (s) 0 0 0 0 1
0 0 1 0 1
0 0 2 0 1
0 0 3 0 1
0 0 4 0 1
0 0 5 0 1
0 0 6 0 1
0 0 7 0 1
Half low frequency period of interest
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NR 493, Sec 3
6.6
Design tension in line components
The total damage D accumulated over one year by the component is then given by the following formula:
6.6.1 The tensions at different locations along the lines, as
3, 15576.10 7 n p j --------------------------------- ---- jk-d j Nk
required for sizing of line components, are to be obtained by the same method as defined in [6.1] to [6.3].
D
When Quasi-dynamic analysis is performed, design tension and other parameters (e.g. uplift angle at anchor point) may be obtained from the catenary with a fairlead position corresponding to the situation leading to the design tension at fairlead.
The maximum width of each tension range interval to be considered should be less than or equal to one thousandth of the mooring line component breaking load, or 10 kN, whichever is less.
Note 1: There may be several positions, with different combinations of offset and vertical position, that are governing for different locations along the line.
7.2
6.7
Minimum tension
6.7.1 When required (fibre rope mooring), the minimum
tension TDm is to be obtained from line Dynamic analysis, by the same method as maximum tension, as: TDm = TM − a TS
7 7.1
7.1.1
For each environmental condition selected as specified in [9.7], the distributions of tension ranges are to be obtained from line dynamic analyses (see App 1, with a minimum duration of 30 min each and a minimum of 10.T 0. Both windward and leeward lines shall be analysed. An appropriate cycle counting method, accounting for both low and wave frequency cycles, such as Rainflow, is to be be used. Miner summation
Fatigue damage in any component of the mooring line is obtained by means of the Miner’s ratio calculated for one year (31 557 600 seconds): 7
D j
=
3, 15576.10 p j --------------------------------d j
where: D j
p j
d j
: Fatigue damage accumulated over one year by the component under the environmental condition number j
for chain mooring line with pretension higher than 10% of the Minimum Breaking Strength (API-ORQ equivalent see [8.3.4]) of the top part of the mooring line. For pretension lower than 10% of the MBS, special consideration may be required by the Society on a case by case basis.
Strength of line General
limitations of position with respect to surface/sea bottom, for certain line segment materials, as specified in Sec 4. 8.1.2 Line segments and connecting devices are to ensure
an homogeneous strength along the line. As a general rule, no weak link is to be provided.
8.2
Breaking strength of line components
8.2.1 The reference load for the evaluation of safety factor
is the minimum breaking strength (MBS) of the mooring line component (see Sec 4) taken into account reduction resulting from corrosion and wear, where applicable (see below and Sec 4). 8.2.2 For chains, the following allowances for corrosion
Note 1: Splash zone area is between +/-5 meters around the free surface. Note 2: Bottom area is the length of line in contact or potentialy in contact with seabed plus 10 meters.
: Probability of occurrence of the environmental condition number j (the sum of the probabilities of all selected environmental conditions should be equal to 1)
The increase could be reduced to 0.3 mm/year in the remaining length.
: Duration of the simulation of the environmental condition number j (normally 10 800 seconds as specified in [9.7]
This change in chain diameter should also be applied for the 5 meters of line in the vicinity of the stopper.
n jk
: Number of cycles within the tension range interval number k encountered by the component under the environmental condition number j
Nk
: Number of cycles to failure at tension range k as given by the appropriate T-N curve.
24
In/Out of Plane Bending (OPB/IPB)
and wear should be taken into account as a minimum. Chain diameter is to be increased by 0,4mm/year in the splash zone and at the bottom area.
n jk Nk ------
k
k
8.1.1 Arrangement of line is to take duly into account the
General
7.1.2
j
7.2.1 Fatigue damage due to OPB or IPB is to be assessed
8.1
Tension range
=
j
8
Fatigue analysis
D j
=
Note 3: These corrosion rates seems relevant for cold seas but may be insufficient in tropical seas.
At a design stage, the current practice for a chain with specified diameter d (see Fig 3 is to consider the breaking strength of the chain of the same grade, with a diameter d c reduced by the specified corrosion (or wear) allowance for the duration of the design life, i.e.: dc
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=
d–c⋅L
April 2012
NR 493, Sec 3
Figure 3 : Modelisation of corrosion for studless links 3,36D 3,36Dc
D 6D
D
5D
5D
Dc
6Dc Dc
2,36D
2,36D
Initial link (D)
Homothetic link (Dc
However, the weight of non-corroded link is to be used for mooring computation.
Corroded link (Dc
where: R
: Ratio of tension range (double amplitude) T to a reference load equal to the line minimum breaking strength, unless otherwise noted below
N
: Allowable number of cycles under tension range T
m
: Inverse slope parameter of T-N fatigue curve
8.2.3 Common practice above is implicitely assuming a
K
: Constant (for a given component).
homothetic reduction of all dimensions in the ration d c /d.
The T-N curve used should be appropriate to the mooring line component and to the type of excitation encountered. Without further information, the T-N curves specified in [8.3.4] to [8.3.6] can be used for mooring line components under pure tension cycles.
For fatigue assessment, a minimum of half of the corrosion (or wear) allowance for the duration of the design life is to be taken into account. Note 4: Higher corrosion rate may be defined based on local regulations or on-site data.
For the evaluation of an in-service system, the breaking strength of a link should be evaluated by strength analysis, taken into account the reduced diameter (see Sec 2, [3.6.5]) but based on non corroded distance between neutral fibre. Moreover, sensitivity on the mooring analysis results should be performed considering corroded MBS and reduced weight.
8.3
General
A fatigue analysis should be performed for installations intended to stay moored on site for a period longer than two years. Change of Unit draft, if any during the period of exposure, should be accounted for. 8.3.2
The fatigue endurance under Tension-Tension (T-T) cyclic loading is given below for typical line components. Reference is to be also made to the relevant requirements of Sec 4. The fatigue endurance (T-N curve) of a line component is written as:
April 2012
Chain
For studlink chain common link, the following parameters of T-N curve may be considered: m=3 K = 1000 Note 1: see also Sec 4, [2.5.2].
Fatigue endurance curve
N Rm = K
8.3.3
For chain, the reference load is to be taken as the minimum breaking strength of an element of the same diameter but in API-ORQ (5.5% less than QR3) quality, for all grades.
Tension-Tension fatigue endurance
8.3.1
The fatigue resistance of the other components is to be evaluated from appropriate sources or by analysis (see Sec 4).
This T-N curve may be assumed to be also applicable to standard end links and to properly designed D shackles (see API RP 2SK, Sec 1, [1.2.5]). The fatigue strength of studless chain is lower: K = 316. Stress Concentration Factor (SCF) in Tension-Tension for the evaluation of global damage (T-T + OPB/IPB) should be taken as 5, unless otherwise documented.
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NR 493, Sec 3
8.3.4
9
Wire rope
Selection of design conditions
The following parameters of T-N curve may be considered:
9.1
• for six/multi-strand wire rope: m = 4,09
General
9.1.1 For a given design condition, a set of time domain
K = 231 • for spiral strand wire rope: m = 5,05 K = 166 Note 1: These data are for a mean load of 30% of rope minimum breaking strength. Fatigue endurance at higher mean load is lower (see references in Sec 1, [1.2.5]). This should be given consideration where applicable.
simulations provides (see [6]) a design tension T D that is a short-term extreme over the duration of the simulations (3 hours), and for the condition analysed. The design tension for each line (or component) is then to be taken as the maximum of T D over all relevant design conditions, i.e. the possible combinations of metocean parameters and configurations of the system, as defined in [9.2] to [9.6] below.
Note 2: Above T-N curves do not cover termination sockets. Fatigue of these structure has to be separately evaluated.
9.1.2 The intact, damaged, and transient cases are sepa-
8.3.5
9.2
Polyester fibre rope
The fatigue endurance of polyester fibre rope may be conservatively assumed to be at least five times that of a spiral strand wire rope of same minimum breaking strength i.e.: m = 5,05 K = 1000 Note 1: Other published curves, with large slope parameter m, would lead to unconservative evaluations and shall not be used.
Attention is drawn to the fact that in a fibre rope mooring, the adjacent steel components will generally have significantly lower fatigue strength than the rope itself. Further guidance for fibre rope analysis may be found in NI432 (see Sec 1, [1.2.2]).
8.4
In/Out of plane bending endurance
8.4.1 Computation of OPB/IPB damage should be based on
Stress Concentration Factor (SCF) coupled with an appropriate S-N fatigue curve to be submitted. 8.4.2 T-T cycling, OPB cycling and IPB cycling are to be
considered as acting together, unless otherwise documented. 8.4.3 With OPB/IPB moments calculated at the center of the
crown section of the considered link, SCF values of 1.5 for OPB and 2.0 for IPB shall be taken into account, unless otherwise documented, considering SCF calculated as follow: σ OP B σ IPB
=
=
M B ----SC F OP B -------OP Z OP B
rately analysed (for transient condition, see [9.6]).
9.2.1 A set of representative configurations of the system
shall be selected for analysis, so as to cover all intended situations of operations of the Unit, and to ensure that the conditions that are the most onerous for the mooring system have been examined. This may include: • variations of Unit draft, in relation with operations (e.g. a Storage Unit) or weather considerations (operating/ survival draft) • connected/disconnected situations, with e.g. an export tanker, or between adjacent vessels (multi-vessel systems) • other relevant conditions. Note 1: For the analysis of a Unit in the offloading conditions, further guidance is given in paper OTC14311 by Morandini & al (reference i) of Sec 1, [1.3]).
9.3 9.3.1
Metocean conditions Metocean data
The metocean data (see Offshore Rules, Part B, Ch 2, Sec 2) are described by the distributions of the intensity of each element as a function of the return period (marginal distribution of independent all-direction extremes), and by associated parameters (e.g. spectral shape and peak period, for waves). Directional data may be used under the condition specified in Offshore Rules, and in App 2. 9.3.2
M SCF IP B -------IP---B Z IP B
System configuration
Design conditions
The metocean design conditions for a N-year return period (see [9.4] to [9.6]) are to be defined as combinations of the direction and intensity of waves, wind, current and associated parameters.
where 3
πd --------16
d
: Corroded diameter of the chain
Depending on the climate, several sets are to be defined in which one of the elements is generally governing, such as: • wave (wind sea or swell) governed conditions • current governed conditions • concomitant swell and wind sea • etc...
w
: Corroded width of the chain.
More detailed information is given in App 2.
Z OP B Z IPB
=
π ( 5d
4
2
2
3
4w d 8 wd ) 16w
+ – -------------------------------------= -------------------
and
26
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April 2012
NR 493, Sec 3
Combinations of intensity and direction
9.4.5 Above return periods apply to manned installations
For each set, the intensity of elements will be selected with values depending on the degree of correlation of extremes, both in intensity and in direction, and on the relative directions between elements.
and to offloading buoys. For unmanned installations, criteria should be defined on a case by case basis.
9.3.3
For both governing and other elements, scanning on the incoming directions shall be performed, over a large enough range for each, so as to provide the evidence that the maximum response has been caught. The criteria in App 2 may be considered for guidance, unless more accurate data are available for the site under consideration. Note 1: in a set of conditions where one element is governing, this element will be generally taken with an intensity corresponding to the N-year return period. Other parameters will be taken as “associated values”, with an intensity that will generally correspond to a lower return period.
9.3.4
Associated parameters
Associated parameters are usually given as a best estimate/most likely value. For the spectral peak (or zero-crossing) period of sea-, as a minimum, a range is to be considered around the specified value. Hs / Tp (or Tz) response contours (inverse FORM approach) may be used when available. See App 2. Similar approach as for period may be applicable to other parameters, when relevant. 9.3.5 The same sets of design conditions will be typically
applicable to both intact and damaged condition of the mooring system. However, the governing conditions may be different. For transient conditions, see [9.6.2].
9.4
Extreme metocean conditions
9.4.1 For a permanent installation, the extreme metocean
conditions are to be taken as the conditions with return period N of 100 years. 9.4.2 For mooring systems other than of permanent instal-
lations (e.g. mobile Drilling Units, Installation vessels, … far away from any other offshore structure, N can be reduced to five times the duration of the operation, without nevertheless being less than 5 years. 9.4.3 For mooring systems other than of permanent instal-
lations, in the vicinity of other offshore structures, N should not be taken less than 10 years. Special considerations as regards the risk of collision may however require that a larger value is used. If a unit working alongside another platform can move away and reach a pre-defined stand-off position within a time reasonably compatible with the local metocean forecast, the provisions of [9.4.2] can be applied to the stand-off position. The environmental conditions beyond which the unit is to move away should be specified in the operation manual and taken into account as an operating condition for the mooring system in working position.
9.5
Operating conditions
9.5.1 The limiting conditions for particular operations (e.g.
offloading, maintenance, working alongside, etc….) shall be specified as either an envelope of possible combinations of elements, or as discrete set of conditions. In such case, the acceptable envelope is to be determined at a later stage, for incorporation in the Unit operating criteria. 9.5.2 When the limiting conditions are infrequent, such as
one year conditions or above, combinations of metocean parameters are to be considered as per [9.3], taking into account the specified return period. 9.5.3 For more frequently occurring conditions, the limit-
ing conditions shall be defined by a set of verifiable limiting values on some metocean parameters. The design operating conditions shall be then established by application of theses limiting values to the sets of N-years (extreme) conditions. 9.5.4 For short-duration infrequent operations not requiring
particular conditions, the operating metocean conditions, when needing consideration, may be taken as the metocean conditions with one year return period conditions.
9.6
Transient conditions
9.6.1 A transient analysis is to be performed in the follow-
ing cases: a) When the Unit is moored in close proximity to a fixed installation, or another floating structure. In this case, analysis may be however limited to the critical lines (line type I in [10.1.1]). b) For operating conditions with specified metocean limiting conditions as defined in [9.5.1] above (e.g. offloading). Analysis may however be omitted in case of a system with large redundancy, as demonstrated to the satisfaction of the Society (e.g. by analysis in damaged condition for the same operating situation being far from critical). In other cases, transient analysis can generally be omitted. Note 1: Mooring systems are considered to be in close proximity to an installation if any part of the other installation lies within a contour described by the set o f offsets coinciding with each line reaching 100% MBS in the intact or redundancy check condition, whichever is larger (see h) of Sec 1, [1.2.5]).
9.6.2 When required, the transient analysis is to be per-
formed for the most critical design conditions of the intact system.
9.4.4
April 2012
9.7
Fatigue analysis
9.7.1 For fatigue analysis, a series of metocean conditions
that are representative of the long term conditions at the intended site, or for the intended operations, are to be considered. This series may be time series obtained by adequate hind-casting, or may be derived from available
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NR 493, Sec 3
statistical data (typically directional scatter diagrams of seastates - or wave systems in multimodal sea-states), combined with wind and current in an appropriate way to take into account joint occurrences. For each condition selected, the fatigue damage, in each segment or component of the lines, is calculated by the Miner sum, taking into account the fatigue capacity, as given in [8.3] above and the duration of the sea-state. From the fatigue damage D calculated for a reference duration of exposure L ref by summation over all conditions considered, the fatigue life FL, i.e. the duration of exposure for which the cumulative damage (Miner sum) would be equal to 1, is obtained as: FL
L re f D
= -------
Note 1: This table is not applicable to hawsers. The relevant safety factors can be found in the Rules for the Classification of Offshore Loading and Offloading Buoys, Sec 1, [1.2.2].
10.1.4 Minimum line tension
For deepwater fibre rope mooring, the following minimum tensions should be considered (see also Sec 1, [1.2.2] b)): • Polyester and HMPE: a positive tension should be maintained in the fibre rope under operating and design conditions. As a guideline, a minimum quasi-static tension of 2% of rope minimum breaking strength (quasidynamic tension in intact condition) may be considered • Aramid and other fibres: 10% of rope minimum breaking strength, in both intact and damaged conditions, unless otherwise documented.
10 Criteria
10.2 Anchors
10.1 Mooring Line 10.1.1
tion analysed, the type of analysis, and other factors as indicated in the notes of Tab 5.
10.2.1 Definition of safety factors
Type of line
Two types of lines are defined: a) Lines of TYPE I are those lines the failure of which leads to a transient response that moves the moored Unit towards an installation in close proximity (see [9.6.1], Note 1, if any. b) Other lines are of TYPE II. 10.1.2 Definition of safety factor
The safety factor is defined as the ratio between the catalogue breaking load of the mooring line component and the maximum tension occurring over its length when the design tension as determined in [6] is applied to the fairlead. 10.1.3 Maximum line tension
At any point of the line, the minimum Safety Factors for line components are specified below, as a function of the condi-
For drag anchors, the safety factor is the ratio between the maximum holding power applicable to the mooring site, and the tangent-to-the-seabed component of the tension in the line at the anchoring point when the design tension is applied to the fairlead. The perpendicular-to-the-seabed component of the load applied to a drag anchor when the line is submitted to its maximum tension (included damaged condition tensions) at fairlead, should remain less than 20% of its wet weight pro jected onto the same direction. For pile driven anchors, the safety factor is the ratio between the maximum load that the pile can withstand in compliance with the requirements of applicable structural and soil mechanics codes and standards, and the tension in the line at the anchoring point when the design tension is applied to the fairlead.
Table 4 : Minimum safety factors for line components
Minimum safety factors (1) (2) Condition of system
Method of analysis (6) Quasi-dynamic
Dynamic
Intact (4)
1,75
1,67
Damaged (4)
1,25
1,25
Transient (3) (5)
1,25
1,20
Damaged (2 adjacent lines removed) (4) (7)
1,00
1,00
(1) (2) (3) (4) (5) (6)
(7)
28
Base factors are for line type II (see [10.1.1]) i.e. not including the case of structures in close proximity. See notes (4) and (5) below. For fibre ropes, an increase of the safety factor in the rope itself (i.e. not including other parts of the line) by 10% for polyester ropes, and 20% for other materials, is recommended. Following methodology in [6.3], and when required. Safety Factor to be increased by 25%, for line ty pe I. Safety Factor to be increased by 40%, for the m ost loaded line, following the breakage of a line type I. The Safety Factor for Dynamic analysis may also be used with the results of a Quasi-dynamic analysis, after the Society agreement, when the characterization of the line response has provided a firm evidence of a dynamic amplification factor (DAF) below 1,0 in all relevant conditions (see App 1).
Only for POSA-HR notation.
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April 2012
NR 493, Sec 3
Table 5 : Minimum safety factors for drag anchors
Minimum safety factors (1)
Method of analysis (5)
Condition of system
Quasi-dynamic
Dynamic
Intact (3)
1,60
1,50
Damaged (3)
1,15
1,05
Transient (2) (4)
1,15
1,05
(1) (2) (3) (4) (5)
Base factors are for line type II (see [10.1.1]) i.e. not including structures in close proximity. See notes (3) and (4) below. Following methodology in [6.3], and when required. Safety Factor to be increased by 25%, for line type I. Safety Factor to be increased by 40%, for the mo st loaded line, following the breakage of a line type I. The Safety Factor for Dynamic analysis may also be used with the res ults of a Quasi-dynamic analysis, after Society ag reement, when the characterization of the line response has provided a firm ev idence of a dynamic amplification factor (DAF) below 1,0 in all relevant conditions (see App 1).
10.2.2 Drag anchors
The minimum safety factors for drag anchors are specified in Tab 5. The factors given in Tab 5 apply only in the case of no uplift at the anchor.
The design service life is the duration, in years, that the moored Unit is intended to stay on site. The fatigue life of the mooring lines should be determined and compared to the service life of the installation if this latter is greater than 2 years. 10.4.2 The minimum fatigue safety factors, for each line
Alternatively, the criteria in App 4 may be applied. 10.2.3 Anchor piles
For long (soft) piles, the safety factors given in Tab 5 also apply to axial pull out capacity, when the angle α of the maximum tension at pile (including inverse catenary effect, if any) does not exceed 15° with horizontal. Otherwise the required pull out capacity is to be increased by a factor K α equal to (1 + 0,33 sin 2α). The factors given in Tab 5 also apply to lateral strength assessment (see Sec 4, [6.2.9]). 10.2.4 Suction anchors and vertical load anchors
A partial factor verification format is given in App 4.
component are: • 3, for all line segments and other components of the lines • 10, for anchors and buried parts • 3, for on-vessel end items • 10, for top segments at support points (see Sec 4, [2.5.3] and Sec 4, [7.2.6]), when the effect of in/out of plane bending or other local actions is taken into account, in addition to T-T fatigue loading. Higher safety factors may be applied, if specified by the Owner.
10.5 Test loading of anchor and lines 10.5.1 The load (at fairlead) for the test loading of anchors
10.3 Clearance 10.3.1 In any condition, the distance between any external
object which the moored Unit is normally not in contact with, and any part of the Unit should remain greater than or equal to ten (10) metres. In any condition, the distance between any point of the mooring line and any external object, either suspended or laying on the seabed, the contact with which could be damageable for either the mooring line or the aforesaid object, should remain greater than or equal to ten (10) metres.
is to be taken not less than the following, depending on the type of the anchor: a) Drag anchors: 80% of the design tension T D at fairlead, in intact conditions b) Vertically loaded anchor (VLA): as required to achieve target penetration and related holding capacity c) Anchor piles and suction piles: as for the line, as specified below. 10.5.2 The load for the test loading of lines is to be taken
More stringent requirements may be specified by operators.
not less than the following, depending on the type of the line:
10.4 Fatigue
a) Steel lines (chain or wire rope): the specified pretension, with some increase (10% minimum is recommended) in order to ensure correct setting of the assembly
10.4.1 The factor of safety in fatigue is specified as a factor
on fatigue life. The Safety Factor is defined as the ratio between calculated fatigue life and design service life of the system (as defined in Offshore Rules, Part B, Ch 3, Sec 3, [1.2.2]).
April 2012
b) Fibre rope (for rope pre-setting): at least 30% of the rope minimum breaking strength (or an appropriate cycling) without exceeding 50% of the rope minimum breaking strength (more details are given in NI 432, Sec 1, [1.2.2]).
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NR 493, Sec 4
SECTION 4
1
COMPONENTS OF MOORING LINES
General
1.1
1.3 1.3.1
Subject
The purpose of this Section is to provide Class requirements related to the components of a mooring system, with a view to the assignment of the POSA notation to a floating unit. 1.1.1
General requirements General
The present [1.3] gives general requirements for all mooring components. The particular requirements for each type of mooring components are given in [2] to [8], in terms of: • design • fabrication and testing (at works or on board)
1.2
Scope
• installation and service conditions.
1.2.1 The components under consideration in this Section
include:
1.3.2
a) main line components, such as:
Reference is made to Rules and related document described in Tab 1, as applicable to particular items, depending on its type of construction (such as forged or cast or fabricated, etc.).
• chain cables and standard fittings • steel wire ropes and terminations
Rules and related documents
• fibre ropes 1.3.3
b) non-standard fittings and connectors c) anchors d) items at the on-vessel end, such as fairleads and stoppers e) ancillary components (buoys, sinkers).
Designation
The components of a mooring line are to be specified by the minimum breaking strength for which the item is designed and tested, and other relevant parameters as specified in [2] to [8].
Deck appliances (winches and windlasses) are excluded from the scope of this Note. Winches or windlasses that are used as stoppers will be given special consideration.
1.3.4
1.2.3 The compliance with the requirements of this Section
When load tests are performed, a Surveyor of the Society shall witness these tests.
1.2.2
are mandatory for the assignment of the POSA notation.
Manufacturing, testing and certification
The manufacturing and testing of the components of a mooring system are to be performed following the applicable provisions of Rules, and under Survey by the Society.
Table 1 : Rules and related documents or standards
Item General Requirements
Defined in [1.3]
Rules and related documents (1) NR216, Rules on Materials and Welding NR445, Rules for the Classification of Offshore Units NR426, Other Rules and publications of the Society, as applicable
Chains and standard fittings
[2]
Steel wire ropes
[3]
Fibre ropes
[4]
NI 432, Certification of Fibre Ropes for Deepwater Offshore Services
Non standard fittings
[5]
NR216, Rules on Materials and Welding, Ch 4, Sec 2
(1)
30
Standards (1)
NR216, Rules on Materials and Welding, Ch 4, Sec 2 IACS UR W22
ISO 1704:1991 API Spec 9A ISO 10425:2003 ISO 2232:1990 API RP 2SK ISO 18692:2007 ISO TS 14909
Complete description of documents in Sec 1, [ 1.2].
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April 2012
NR 493, Sec 4
1.3.5
Type approval
2.3.3
Materials
When specified in [2] to [8], items are to be type approved by the Society according to the requirements of the present Section.
Chains and standard fittings are to be made of materials in grade QR3, or QR3S, or QR4, or QR4S, or QR5, as specified in Rules on Materials and Welding, Ch 4, Sec 2.
For type approval, the documentation of design is to be submitted for review and the manufacturing and testing of prototype items are to be performed under Survey by the Society, as required for the item under consideration.
The use of ORQ grade is generally not permitted within the framework of the POSA notation.
Note 1: The range of sizes, or other parameters for which approval is granted will be specified at ti me of approval.
For a particular project, once an item is holding a type approval: • the documentation of design may be limited to project specific information, and to documentation of the adequacy of the item for the intended project • the provisions of [1.3.4] are applicable to manufacturing and testing of items for the intended project.
2
Chains and standard fittings
Grades higher than QR5 will be given special consideration.
2.4 2.4.1
General
2.1.1 The items covered in the present [2] are chain com-
mon links, connecting common links, enlarged links, end links, detachable connecting links, end shackles, swivels and swivel shackles. 2.1.2
Rules and related documents or standards
Reference is made to Rules and related documents described in Tab 1.
2.2
Designation
2.2.1 Chain and accessories are to be specified by their
Manufacturing
Chains and standard fittings are to be manufactured according to the criteria specified in Rules on Materials and Welding, Ch 4, Sec 2. Chains and standard fittings are to be manufactured only by Manufacturers approved by the Society for the intended product. 2.4.2
2.1
Manufacturing and testing
Load Tests
The chain cables and their fittings are to be tested and examined as required in Rules on Materials and Welding, Ch 4, Sec 2. Each chain link or standard fitting is to be tested at a proof load PL depending on the required Breaking Strength MBS and the specified material grade, as per Rules on Materials and Welding. The ratio of proof load to Minimum Breaking Strength is given for reference in Tab 2. Break load tests are to be carried out in the conditions specified in Rules on Materials and Welding. Note 1: Items that have been subject to a break load test are to be generally scrapped.
Minimum Breaking Strength and grade, or by nominal diameter and grade.
Table 2 : Ratio PL/MBS
Note 1: For accessories, the nominal diameter is the nominal (bar) diameter of the corresponding chain.
Type of chain
QR3
QR3S
QR4
QR4S
QR5
2.2.2 The specified nominal diameter/MBS is to include an
Stud-link
0,66
0,72
0,79
0,79
0,78
adequate margin for corrosion and wear over the intended service life (see Sec 3, [8.2]).
Studless
0,66
0,70
0,70
0,70
0,70
2.3
2.5
Design
2.3.1
2.5.1 The deployment of lines is to be performed in such a
Design documentation to be submitted
Drawings giving the detailed design of chain and accessories are to be submitted for review at the time of approval. Fatigue documentation has to be submitted for review (see also [5.3.4]). 2.3.2
Dimensions
The dimensions of stud chains and standard fittings are to be as per Rules on Materials and Welding (typical designs). Alternatively, reference may be made to ISO 1704. For studless chains, dimensions are to be in accordance with the Manufacturer's specification. Note 1: In case dimensions are not in accordance with specifications, component has to be considered as n on-standard (see [5]).
April 2012
Installation and service conditions
way as to avoid jamming on the bottom, and accumulation of twist, that may result in damage to the chain itself or to other components, when the line is tensioned. 2.5.2 Attention is drawn to the fact that the fatigue perfor-
mance of studlink chain might be significantly decreased in the case of loose studs. The T-N curve given in Sec 3, [8.3.3] applies to links with tight studs. 2.5.3 Attention is to be also given to the risks of bending
fatigue of chains over stoppers, bending shoes of fairleads (see also [7.2.6]). Where possible, regular and frequent adjustments of mooring lines are to be carried out in order to mitigate accumulation of fatigue damage in the line at these locations.
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NR 493, Sec 4
3
Steel wire ropes
3.1 3.1.1
• sacrificial anode wires • sheathing • additional corrosion and wear allowances.
General Scope
The present [3] covers steel wire ropes intended for mooring lines and associated termination fittings. 3.1.2
3.3.4
3.4
Designation
3.4.1 3.2.1 Steel wire ropes are to be specified by their Minimum
Breaking Strength, and by the type of construction and nominal diameter. 3.2.2 The specified nominal diameter/MBS is to include,
where applicable, a margin for additional corrosion and wear allowance (see [3.3.3]).
3.3 3.3.1
Design of steel wire rope Design documentation to be submitted
As a minimum, the following documents or information are to be submitted for review: • reference standards • specification of wires • specification of other materials (galvanic coating, compound, sheathing) • calculation of wire rope static strength • documentation of torque properties (tension induced torque and torque compliance) • cathodic protection calculations • fatigue analysis, for the intended application.
Design documentation to be submitted
As a minimum, the following documents or information are to be submitted for review: • drawings of termination fittings • specification of materials • strength and fatigue evaluations • corrosion protection drawings and calculations • details of electrical insulation and data sheets of relevant materials • drawings of connection to ropes, with specification of socketing material. 3.4.2
Design requirements
The strength of termination is to be not less than the specified minimum breaking strength of the wire rope (see also [3.5.2] below). Terminations are to provide an effective electrical isolation between the wire rope and the rest of the mooring line. Termination fittings are to be fitted with cathodic protection, to a level consistent with that of the wire rope.
3.5
Construction
Rope constructions considered in the present document include: • six-strand construction (with steel core) • multi-strand constructions • spiral-strand construction (including half locked and full locked coil). 3.3.3
Design of Terminations
Terminations are to be designed in accordance with the requirements given in [5].
• rope construction drawing and specification
3.3.2
Strength
The calculated breaking strength is not to be less than the specified minimum breaking strength (see also [3.5.2].
Standards
Reference may be made to Standards described in Tab 1.
3.2
Note 1: T-N data in Sec 3, [8.3.4] are valid only when a suitable corrosion protection is provided.
3.5.1
Manufacturing and testing Manufacturing
The following documents or information are to be submitted in due course: • reference standards • quality and test plans with proposed witness points for the Surveyor • process monitoring and recording (including traceability) • acceptance criteria
Protection
Protection against corrosion and resistance to wear is to be provided, including at least:
• steel rod raw material certificates • sheathing procedure
• wire galvanisation, or equivalent
• repair procedures • procedure for connection of terminations to rope, • individual wires records
• stranding compound. Complementary protection by one or several adequate means are to be provided as necessary, considering service conditions and intended life time. This may include means such as: • selection of the type of construction and wire profile • improved galvanic coating
32
• manufacturing documentation of termination (see [5.3.1] below) • records of connection of terminations to rope • rope sample test procedures • rope sample load test reports.
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NR 493, Sec 4
3.5.2
4.2
Testing
A break load test is to be carried out on a sample of the wire rope and its terminations, taken off the production under Survey. The sample is to withstand the specified MBS.
3.6
Design
4.2.1 Fibre rope is to be identical to the approved rope.
Termination thimbles are to be made of the same type of material (steel), same groove profile and same inside diameter (within −0 / +10%) of those used for prototype testing. 4.2.2 Fibre ropes are not to be used in lines including six-
Installation and service conditions
3.6.1 The deployment of lines is to be performed in such a
way as to avoid:
strand wire rope or other non-torque-balanced components, unless a torque-matched construction is provided.
4.3
• damage by over-bending or chaffing over obstacles • over-bending in free span, by maintaining a suitable minimum tension • excessive bending at terminations: Bending restrictors are to be provided as necessary • accumulation of twist, particularly in case of a nontorque compliant structure • any damage to sheathing (when provided). 3.6.2 The use of wire rope is generally not allowed in the
touchdown area.
Manufacturing and testing
4.3.1 Manufacturing and testing of fibre rope are to be per-
formed in accordance with the requirements of NI432, under Survey by the Society. 4.3.2 Thimbles are to be manufactured and tested in accor-
dance with the provisions of [5]. However, load tests may be omitted for steel roller thimbles (spools), when a thimble of same material, and with same or proportional dimensions, has been tested together with the rope, at time of rope approval, for a similar or higher MBS.
Unless periodical renewal is planned, the use of wire rope is to be also avoided in the splash zone of long term moorings.
4.4
Attention is also to be given to the risks of bending fatigue of rope over fairleads. Where possible, regular and frequent adjustments of mooring lines are to be carried out in order to mitigate the accumulation of fatigue damage in the line at these locations.
way as to avoid damage by chaffing, cutting, or over-bending over obstacles, as well as contamination by solid or by liquid projections. Any contact with the seabed is to be avoided. Seizing of line, or of ancillary installation devices on line is to be performed by soft rope seizing only.
4
Fibre ropes
4.1
Installation and service conditions
4.4.1 The deployment of lines is to be performed in such a
Lines are to be deployed under a low tension, with however a suitable minimum tension being maintained, to avoid the risks of local over-bending.
General
The accumulation of twist is to be avoided. 4.1.1
Scope
The present [4] is applicable to fibre ropes intended for use as anchoring lines, and covers both fibre rope and termination thimbles. Note 1: For mooring hawsers, see N R494, Sec 4, [5].
4.1.2
Designation
Fibre ropes are to be specified by a Minimum Breaking Strength, and the type of material. 4.1.4
Approval
Fibre ropes are to be Type Approved by the Society according to the requirements of NI432. Note 1: type approval is based on full size testing of a prototype rope, of the specified MBS.
Termination thimbles other than steel roller thimbles (spools) shall be in accordance with the requirements of [5].
April 2012
specified in NI432.
5
Non standard fittings
5.1
Rules and related documents
Reference is made to Rules and related documents described in Tab 1. 4.1.3
4.4.2 The service conditions of the fibre rope are to be as
5.1.1
General Scope
The present Article [5] addresses fittings for connection between line elements, having general dimensions or use deviating from those given in the Rules or recognised standards, such as: • special links and enlarged shackles with general dimensions different from ISO 1704 (e.g. for connection to a fibre rope thimble) • H-links (straight and twisted) • tri-plates • connectors (for underwater connection) • termination fittings for wire ropes • termination thimbles (special type) for fibre ropes (see [4]).
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NR 493, Sec 4
5.1.2
Rules and related documents
5.2.4
The present [5] primarily addresses fittings that are made of cast steel, forged steel, or machined from steel plates, for which reference documents described in Tab 1. 5.1.3
Designation
Fittings are to be specified by a Minimum Breaking Strength and, as relevant, the nature and nominal dimensions of the items they are intended to connect. For items connecting ancillary line elements, the Minimum Breaking Strength of attached elements is to be also specified. 5.1.4
Type Approval
Fittings that are not purpose-designed for a specific system are to be type approved by the Society according to the requirements of the present Section. Fittings that are purpose-designed for a specific system are to be approved following the requirements of the present [5].
5.2 5.2.1
Fatigue
The resistance to fatigue is to be documented. The fatigue resistance is to be established with reference to data for line components (see Sec 3, [8.3]) and, as a rule, is to be not lower than the fatigue resistance of a chain of the same breaking strength in grade QR3. Besides, for a particular project, the achieved fatigue life is to be documented, and is to meet the relevant requirements of Sec 3. 5.2.5
Protection
Protection against corrosion and wear is to be provided by adequate means. For high yield strength materials, attention is however to be given to risk of hydrogen-induced cracking. Electrical isolation of connectors is to be provided as applicable. 5.2.6
Functional requirements
Designer is to ensure that all detachable parts are adequately locked in position by passive means.
Design
Connectors are to maintain a positive stability under a low tension, and are to be fitted with a locking system.
Design documentation to be submitted
As a minimum, the following documents or information are to be submitted for review: • drawings, with the detailed design of fittings and all parts made by or supplied through the manufacturer
Note 1: Where applicable, a minimum tension is to be specified, and the device is not to be allowed for use on sea bottom nor in touch down area.
5.3
• specification of materials
Manufacturing and testing
• strength and fatigue evaluations
5.3.1
• corrosion protection drawings and calculations, where relevant.
The following documents or information are to be submitted in due course:
5.2.2
Manufacturing
• reference standards
Material
Fittings in cast or forged steel, or machined from steel plates, are to be made of materials meeting the requirements of one of the following Rules grades: QR3, or QR3S, or QR4, or QR4S, or QR5. Where applicable, steel with yield and tensile strength lower than QR3 may be used, provided other mechanical properties of grade QR3, in Rules on Materials and welding, Ch 4, Sec 2, Tab 1, are met. The specification of material is also to include reference to a recognised material Standard, with details of chemical composition and heat treatments. In the case of a welded assembly, the provisions of [7.2.3] are also to be met, with a design temperature of 4°C, unless otherwise specified. Note 1: Any welding onto QR4 steel is g enerally prohibited.
• quality and test plans with proposed witness points for the Surveyor • fabrication and testing procedures and records. 5.3.2
Qualification
The manufacturer shall be recognized and approved for the forging/casting of the intended mooring line accessories. 5.3.3
Break load tests
Proof and break load tests are to be carried out on a prototype item, as per Rules. Consideration is to be given to tests made on items of different sizes, with proportional dimensions. For shackles, detachable links, and similar items, break lo ad tests are to be carried out as for standard items (see [3.5.2]).
The strength is to be documented by appropriate calculations, in accordance with the provisions of App 3.
When load test might not be achievable for technical reasons, the test may be dispensed, with prior agreement with the Society, subject to adequate documentation of strength, by analysis.
Note 1: Elasto-plastic analysis is generally required when a verification by a break load test is not performed (see [5.3]).
Note 1: Items that have been subject to a break load test are generally to be scrapped.
5.2.3
34
Strength
Bureau Veritas
April 2012
NR 493, Sec 4
5.3.4
Proof load tests
Each item is to be tested at a proof load depending on the required Breaking Strength and the specified material grade, as given for studless chain in Tab 2. When load test might not be achievable for technical reasons, replacement of the proof load test by other suitable examinations may be considered on a case by case basis by the Society.
• drawings, with the detailed design of all parts made by or supplied through the manufacturer • geotechnical strength evaluations, and supporting test reports • specification of materials • strength and fatigue evaluations • corrosion protection drawings and calculations. 6.2.2
6
Anchoring devices
6.1
General
The geotechnical ultimate capacity of an anchoring device is to be documented (see [6.2.7] to [6.2.9] below). The effects of cyclic loading are to be assessed.
Scope
Behaviour during installation and related loads are also to be assessed and documented.
6.1.1
The present [6] covers anchoring devices such as: • drag anchors (except as quoted below)
For a particular application, an evaluation of the feasibility of the proposed type of anchoring device with respect to the soil profile is to be provided, and the geotechnical ultimate capacity of proposed device shall satisfy the requirements of Sec 3, [10.2].
• vertically loaded anchors (VLA's) • suction anchors • anchor piles. The present [6] does not address conventional (ship type) drag anchors, that are designed, manufactured and tested in accordance with the relevant provisions of the Ships Rules. Such type of anchor is not normally used in permanent moorings. Other types of anchoring devices are to be given special consideration, on a case by case basis. 6.1.2
Designation
Anchoring devices are to be defined, as a minimum, by the required ultimate holding capacity and related uplift angle at anchor lug. When required to verify the design (see [6.2]), the details of loads in each design condition are to be also specified. 6.1.3
Approval
Drag anchors and VLA's are to be type approved by the Society on the basis of the present document. Note 1: The type approval is generally delivered for a specified range of sea-bottom conditions. Note 2: Other type of anchoring devices are ge nerally approved for the particular application for which they are specifically designed.
6.2
Geotechnical design
Design
6.2.1
Design documentation to be submitted
As a minimum, the following documents or information are to be submitted for review, as applicable to the type of anchoring device: • specification of design soil conditions (for type approval), and documentation of conditions at testing site (see [6.2.7]) • documentation of site conditions (see Offshore Rules, Part B, Chapter 2), including the study of possible geohazards • design loads at anchor lug, with details of derivation from loads in line at sea-bottom • loads/design conditions at time of installation
April 2012
Note 1: For most types of anchoring devices, the full design geotechnical capacity may be not available immediately after installation, due to the time required for set-up effect of soils (particularly clays). This should be given consideration in the overall scheduling of a project, taking into account the risk of occurrence of high load during that period.
6.2.3
Materials
Materials are to conform to the relevant sections of Offshore Rules and Rules on Material and Welding (offshore grades), taking into account design temperature and structural categories, as defined in [6.3.2]. 6.2.4
Strength
The strength is to be documented by appropriate calculations, in accordance with the provisions of App 3. Anchor pad-eye, shanks, and adjacent structure are to be designed to withstand the minimum breaking strength of the line. The anchor body is to be able to withstand the ultimate capacity of the anchoring device, with deformations within such limits as not to impair anchor geotechnical capacity (see [6.2.9] however). 6.2.5
Fatigue
The resistance to fatigue is to be documented. The data referenced in [5.2.4] may be used as guidance for the purpose of type approval. For a particular project, the achieved fatigue life is to be documented, and in accordance with the relevant requirements of Sec 3. 6.2.6
Protection
Protection against corrosion is to be provided by adequate means. When the geotechnical capacity of the anchor is relying on skin friction between soil and steel, the surface condition of steel is to be consistent with the assumptions made at time of design. Note 1: Where appropriate, protective coating should be avoided in the relevant a rea of the anchor.
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NR 493, Sec 4
6.2.7
6.4
Particular provisions - Drag anchors and VLA’s
The geotechnical behaviour of drag anchors and VLA's is to be documented by testing of a prototype anchor in representative soil conditions. Complementary analysis, where applicable, may be used. For VLA’s, the relations between achieved penetration (and related load), soil parameters, and ultimate capacity of the anchors are to be established and documented by these tests. 6.2.8
Particular provisions - Suction piles
The geotechnical capacity of suction piles may be established by analysis, with due consideration of the potential modes of failure under the combination of vertical load, horizontal load, and overturning moment. In strength evaluation, due attention is to be given to the buckling resistance of the anchor body with respect to the under-pressures generated by suction effects, at installation or in service. 6.2.9
Particular provisions - Anchor piles
The design of long (soft) anchor piles may be documented in accordance with recognised procedures, such as those specified in API RP 2A (see Sec 1, [1.2.5], where: • the pull-out capacity (axial load) and the strength under lateral load can be evaluated separately • the strength of pile under lateral load is assessed considering factored loads (e.g. as per API RP2A-LRFD, see Sec 1, [1.2.5]), with load factors taken as per Sec 3, Tab 5.
6.3 6.3.1
Manufacturing
• Offshore Rules, Part B, Chapter 3 • Rules on Materials and Welding, Ch 2, Sec 3 and Sec 4 • NR426 Construction Survey of Steel Structures of Offshore Units and Installations. Structural categories and design temperature
For the selection of materials, and the definition of fabrication and NDT requirements, the following categories of construction (as defined in Offshore Rules, Part B, Ch 3, Sec 2) are to be considered: • pad-eye, shank, and adjacent structure are to be considered as “Special Category elements” • the rest of Anchor body is to be considered as “First Category” elements • a design temperature of 4°C is to be generally considered for anchoring devices in deep waters. In other cases, the design temperature is to be specified.
36
6.4.1 The installation at site of anchoring devices is to be
performed under Survey by the Society (see Sec 2, [2.5]). Installation procedures for anchor setting and pre-loading are to be submitted in advance for review by the Society. Anchor and line test loading are to be performed as required in Sec 3, [10.5]. Installation records, with related analyses, as needed, are to provide evidence that target penetration/holding capacity have been achieved.
7
Items at the on-vessel end
7.1 7.1.1
General Scope
The present [7] cover items at the on-vessel end, that are intended for guiding and securing anchoring lines to Unit, such as: • fairleads or bending shoes • stoppers • supporting structures for the connection to Unit hull of above items. Note 1: The foundations of these items into the hull (or turret as applicable) are covered by the main Class of the unit (see however [7.2.5] below). Note 2: For winches, windlasses and other deck appliances, see [1.2.2].
7.1.2
Designation
Items are to be specified by the nature and nominal dimensions of the line segment they are intended to support, and the related Minimum Breaking Strength. 7.1.3
Manufacturing
The manufacturing of anchoring devices is to be performed under Survey by the Society, in accordance with the relevant requirements of:
6.3.2
Installation
Approval
Items are generally approved for the particular application for which they are specifically designed. Standard items may be type approved by the Society on the basis of the requirements of the present [7] and relevant sections of the Rules and related documents.
7.2 7.2.1
Design Design documentation to be submitted
As a minimum, the following documents or information are to be submitted for review, as applicable to the type of item: • drawings of arrangement, construction, and mechanical components, with the detailed design of all parts made by or supplied through the manufacturer • design loads and other relevant design conditions • detailed structural drawings • specification of materials • strength and fatigue evaluations • documentation of mechanical components • documentation of interface loads • interface drawings • corrosion protection drawings and calculations.
Bureau Veritas
April 2012
NR 493, Sec 4
7.2.2
Design conditions
Items are to be designed to withstand the line segment they are intended to support, when loaded to: • a Design Breaking Strength, equal to the Minimum Breaking Strength of the line segment (see however Note 1 below)
In this respect, attention is to be given to minimise out of plane bending in chain, and to locked-in modes that may arise in relation with friction between parts within the load path between free spanning line and Unit body. 7.2.7
Mechanical components
• the design tension TD in line, in each condition of the mooring system (intact, damaged, transient, as relevant).
Mechanical components are to be of a suitable type with respect to functional requirements (e.g. low friction properties) and durability in marine environment/seawater.
Note 1: When the on-vessel end of the line includes an oversized upper segment, the Design Breaking Strength may be taken as the load at fairlead corresponding to a load in the next segment equal to the MBS of that segment.
Mechanical components are to be able to withstand internal loads induced by the Design Breaking Strength in the line, and operate under the highest design tension T D in line.
Note 2: For type approval, TD is to be taken as the Design BS divided by the minimum required safety factor as specified in Sec 3.
For items supporting the free spanning line, due attention is to be given to the range of orientation of line load that will result from tolerances in system geometry, Unit offset and Unit motions, in addition to those resulting from possible configurations or predicted by mooring analysis. 7.2.3
Materials
Materials are to conform to the relevant sections of Offshore Rules and Rules on Materials and Welding (offshore grades), taking into account design temperature and structural categories, as defined in [7.3.2]. 7.2.4
Parts requiring replacement are to be identified, and criteria specified. 7.2.8
Protection
Protection against corrosion and wear is to be provided by adequate means. For submerged items, consideration may be given to complementary cathodic protection (when electrical bonding is provided to benefit from Hull CP system), or independent protection.
7.3
Manufacturing and testing
Strength
The strength is to be documented by appropriate calculations, in accordance with the provisions of App 3. Items are to be designed to withstand the loads specified in [7.2.2].
7.3.1
Manufacturing
The manufacturing of items shall be performed in accordance with the relevant requirements of: • Offshore Rules, Part B, Chapter 3
Parts supporting mechanical components are to have, under the highest design tension TD, deformations within such limits as not to impair the integrity of mechanical components.
• Rules on Materials and Welding, Ch 2, Sec 3 and Sec 4
7.2.5
7.3.2
Interface with Unit structure
• NR426 Construction survey of steel structures of offshore units and installations. Structural categories and Design temperature
Loads and load distribution at interface with Unit structure are to be documented.
For the selection of materials, and the definition of fabrication and NDT requirements:
Interface arrangement and weld details are to be specified, in a manner consistent with the arrangement of underneath Unit structure, in order to ensure suitable structural continuity. Attention is to be given to thickness transitions between materials of different strength.
• principal load bearing items and adjacent structure are to be considered as "special category" elements
7.2.6
Fatigue
The resistance to fatigue of items and interface connections is to be documented. The data referenced in [5.2.5] may be used as guidance for the purpose of type approval. For a particular project, the achieved fatigue life is to be documented, and in accordance with the relevant requirements of Sec 3. Possible detrimental interaction with the mooring line is to be assessed and taken into account for the design of the upper segment of the line, as well as for the design of the item itself.
April 2012
• the rest of the body of items may be considered as "first category" elements • the design temperature is to be specified, and taken not higher than the design air temperature for the Unit. The (near-surface) seawater design temperature may be however considered for permanently submerged parts. 7.3.3
Testing and on-board installation
The onboard installation of items is to be performed under Survey by the Society. Interface welds are to be considered as “special category” elements (100% NDT). Functional testing is to be performed, in workshop as far as practicable, and after on-board installation, following an agreed program.
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NR 493, Sec 4
8 8.1
Ancillary elements
8.1.3 Design criteria, materials, surveys during manufactur-
ing and testing, as applicable, are to be carried out to the satisfaction of the Society.
General
8.1.1 The present [8] is addressing ancillary items such as
buoys, sinkers and their connections, that are permanent parts of the mooring system (see Sec 2, [1.3.1]). 8.1.2 Drawings, preliminary design calculation notes and
material specifications shall be submitted. Based on this documentation, additional calculations and tests may be required. As a general matter, manufacturing and testing shall fulfill requirements of Material Rules and Offshore Rules ( Sec 1, [1.2.1] a) and b)).
38
8.2
Service conditions
8.2.1 The failure of any of these components to fulfil its
function is to be considered in the design of the mooring system as a damaged case. 8.2.2 Dispositions are to exist in order to ensure the integ-
rity of the mooring system at any time. These dispositions are to be submitted to the Society for review.
Bureau Veritas
April 2012
NR 493, App 1
APPENDIX 1
1
CHARACTERISATION OF THE LINE RESPONSE
General
1.1
1.2.3 The Quasi-Dynamic analysis is sufficient, if one the
following condition is satisfied: a) based on the above tension criteria:
Test run
1.1.1 A characterisation of the line response is to be per-
formed in order to obtain information on the respective contribution of mean load, slow drift, and wave frequency motions to the line tension, the level of dynamic tensions, and to evaluate if Quasi-Dynamic analysis can be sufficient. A relatively short run (10 to 15 mn real time) will be generally sufficient. Conditions of run should be taken as close as possible to those of the “wave governed” case leading to maximum Quasi-Dynamic tensions at fairlead (or other point of interest) in the governing (intact or damaged) situation. 1.1.2 The time series of the Quasi-Dynamic tension T qd and
of the dynamic tension T dyn are to be written as: Tqd = Tmean + Tlf + Twfqd Tdyn = Tmean + Tlf + Twfdyn where: Tmean
: Mean tension
Tlf
: Low frequency tension variation.
Twfqd and Twfdyn are respectively the Quasi-Dynamic and the Dynamic wave frequency variations, thus obtained by difference between the total signal and the previous terms. T lf , Twfqd and Twfdyn can be characterised by their standard deviation σlf , σwfqd and σwfdyn.
1.2
Characterisation
Tmean and Tlf are to be checked for consistency between Dynamic and Static response analyses, 1.2.1
1.2.2 The significance of Dynamic tension can be assessed
from: DAF = σwfdyn / σwfqd Note 1: The ratio of total (maximum) tension T maxdyn /Tmaxqd from time domain simulation is not a proper indication, and cannot be called a “DAF”
April 2012
1, 9 D AF σ ------σ lf > --------------------------------wfqd 3, 2 – log T 0
where: DAF : Coefficient defined in [1.2.2]. DAF is to be taken not less than 1 T0 : Largest natural period defined in Sec 3, [3.1.1]. In that case, the low frequency part of the tension is governing over the wave-frequency part. b) or: 1,75 (M + 1,8 S) > 1,67 (M′ + 0,7 S′) and, if the analysed case is a damaged condition: M + 1,8 S > M ′ + 0,7 S′ where: • M and S are the mean and the (n − 1) standard deviation of the maximum tension over 5 simulations, in the same conditions • M' and S' are estimators of the same quantities in case of a dynamic simulation, that are obtained by: S′ = DAF ⋅ S B = M − (Tmean + 2 σlf ) M′ = M + B (DAF − 1) 1.2.4 In the case of [1.2.3] a) above, and only when DAF is
undoubtedly below 1, the Safety factors for Dynamic analysis may be used with the results of a Quasi Dynamic analysis. 1.2.5 When line dynamic is prevailing, plot of T dyn versus
Tqd and Tdyn versus dT qd / dt will indicate to which of these Tdyn is correlated, as needed for the selection of windows for dynamic analysis. 1.2.6 For the scanning through combination of Unit condi-
tions and metocean parameters, the following tension criteria (based on APIRP2SK Sec 1, [1.2.5]and the above data) may be used, with the results of a single Quasi-Dynamic simulation for each combination: a) when Low Frequency is prevailing over Wave Frequency for tension variations: TAL = Tmean + (4,9 − 0,9 log T0 ) σlfqd + 2 σwfqd b) otherwise: TAW = Tmean + 2 σlfqd + 3,7 DAF σwfqd
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NR 493, App 2
APPENDIX 2
COMBINATION OF METOCEAN PARAMETERS
Symbols H
: Waves
S
: Swell
W
: Wind sea
V
: Wind
C
: Current
2
Metocean data
2.1
Metocean conditions and design data
2.1.1 The metocean conditions at a given site are generally
H-V, C-V: Relative directions between waves and wind, and between (near) surface current and wind, respectively. Relative headings are between incoming directions and are taken positive when clockwise, viewed from above, in the Northern Hemisphere, and anti-clockwise in the Southern Hemisphere
based on site measurement, or may be derived from satellite data or by hindcasting, duly validated by site measurements.
RP
: Return period
N RP0
: Specified return period, n = log(N) : Reference return period, r0 = log(RP0) (see [3.3])
The processing of data base should also provide adequate joint statistics of parameters.
nXd
: Number of exceedance per year: nXd = 1 / RP
r
: Reduction factor (see [3.3])
pe(X)
: Probability of exceedance of X: pe(X) = p(x>X)
pasi
: pe for associated independent parameters.
1 1.1
The processing of such data base will provide metocean design data (extremes). The statistical techniques used for that are to be documented to the satisfaction of the Society.
2.2
Intensity and direction
The metocean data are normally available as the intensity of each element (wind speed, current speed, wave -or wave system- significant height), in function of the return period (independent all-directions extremes). 2.2.1
General
2.2.2 When available, directional data (i.e. different values
Subject
1.1.1 This Appendix defines the combinations of metocean
parameters to be considered as design metocean conditions for a mooring system (station-keeping, offshore tandem or side by side mooring, ….). The criteria herein may be considered for guidance, as minimum requirements, that may be adjusted when more accurate data are available for the site under consideration. 1.1.2 These criteria are also applicable to heading analysis
per sectors of incoming -geographical- direction) may be used, provided they are consistent with all-direction data, as detailed hereafter. Directional data are derived from joint (or conditional) distributions of intensity and incoming sector. Inconsistent variations between adjacent (small) sectors should be removed by appropriate means, and values should be properly "rescaled" as defined hereunder (see paper j) in Sec 1, [1.3]).
and sea-keeping analysis in extreme conditions (short term approach). In such cases, it will be most often necessary to consider intermediate combinations between those defined herein.
Given:
Note 1: The approach is that the possible metocean design conditions for a N-year return period form a response contour, in the sense of the Inverse-FORM methodology, so that the N-year response is the maximum response over all possible design points.
pe(X,∆Θk): The joint probability of exceedance of X in sector ∆Θk
The N-year contour is notionally a hyper-surface in a multi-variate space. It is simplified here as a set of discrete combinations with generally one governing element, and "associated values" for the others.
X*
∆Θ*
: The all-direction extreme value of an intensity variable X at a given return period
: The most probable sector for exceedance of X*,
thus: pe(X*, ∆Θ*) ≥ pe(X*, ∆Θk)
The true contour (or a subset of it) should be considered if supported by adequate data and where needed.
∆Θ* is also the incoming sector of the maximum of the
See paper j) in Sec 1, [1.3].
directional values X k (at the same return period).
40
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Then the values Xk at the same return period in each sector ∆Θk should be such that: • in sector ∆Θ*: Xk = X*, i.e. the maximum (over all sectors ∆Θk) of Xk is taken equal to the all-direction extreme value X * at the same return period • in other sectors: Xk should be taken such that pe(X k, ∆Θk) = pe(X*, ∆Θ*), or lower. Besides, Xk=0 when p( ∆Θk), the probability of incoming direction being in sector ∆Θk is such that: p(∆Θk) ≤ pe(X*, ∆Θ*) Note 1: p(∆Θk) = pe(0, ∆Θk)
2.3.3 HS /TP (or HS /TZ) response contours (inverse FORM
approach - e.g. see paper j) in Sec 1, [1.3]) may be used when available, and are to be preferred when the response is found very sensitive (to wave period). Contours are to be defined, covering a range of return periods. Where relevant (and possible), directional contours (i.e. different HS /TP contours for different sectors) should be defined. The contour having its maximum at the specified HS shall be selected, then scanned for the most onerous H S /TP combination (i.e. the combination leading to the maximum response). However, taking a plateau (i.e. no reduction of HS) over not less than ± 10% around the specified period is recommended. See Fig 1. Figure 1 : H S /TP contour (for illustration)
2.2.3 For “frequent values” (see [3.3.5], when needed, the
all-direction value can be obtained from the observed (marginal) distribution of the considered parameter. Directional values can be then derived following the same method as above. Note 1: The intensity for intermediate return periods between those quoted in the specification may be obtained by linear interpolation of intensity as a function of the (decimal) log of return period (i.e. of the factor r defined in [3.3]), or by fitting the data to an adequate extremal distribution.
9 8 7 6
) m5 ( s H4
3 2 1 0
Note 2: When RP is less than one year, it is more representative to quote: •
the number of exceedance, per year: nXd = 1 / RP, or
•
the probability of exceedance, in % of time (based on 3-hour sea states): pe = 100 nXd / 2922
The intensity for a specified pe may be then obtained by linear interpolation of intensity as a function of the (decimal) log of pe, on the observed distribution. Note 3: When the intensity is defined for a discrete set of incoming directions, the same value applies to any other direction within the sector around each specified direction.
2.3
Sea-states
0 1 2 3 4 5 6 7
Observed data
Theorical contour at targeted RP
Practical contour
Operational contour
2.3.4 For spectral peakness parameter, when waves (or the
sea-state component) are quoted as the governing parameter, a range of values should be considered unless, depending on available data, a relation with e.g. steepness (or other relevant parameter) can be documented. In other cases, the specified (mean) value may be used.
2.4
2.3.1 A Sea-state may be described by:
8 9 10 11 12 13 14 15 16 17 18 19 20 Tp(s)
Wind
2.4.1 The design wind speed V is to be selected as per
• a wave spectrum (unimodal sea-state), or • the sum of several wave spectra (for multimodal -and generally multidirectional- sea-states). Each spectrum is defined by its significant wave height H S, the period TP (or TZ) , and additional parameters as relevant for the specified spectral shape (e.g. the peakness factor γ for a JONSWAP spectrum). The significant wave height H S is to be selected as per [3.3].
[3.3]. Sustained winds are specified by the 10 minute or 1 hour average speed (see Sec 3, [3.1] and Sec 3, [3.2]), typically at 10m above the sea level. 2.4.2 Squall winds are defined from records of wind speed
and direction with time. For input to analysis, the record is adjusted as follows:
2.3.2 Associated parameters are generally available as a
a) the wind speed record V(t) is rescaled to get the design 1 minute mean speed.
best estimate/most likely value.
Note 1: The rescaling factor is thus V 1' specified / V1' max,
For the spectral peak (or zero-crossing) period T P (or TZ), when waves (or the sea-state component under consideration) are quoted as the governing parameter, a range is to be considered around the specified value, as a minimum. A range of ± 15% (around the specified value) should be considered. However, the minimum period may be adjusted, based on considerations of minimum steepness at considered site.
April 2012
Bureau Veritas
where V1' max is taken equal to: •
the maximum velocity in the record, if time step of record is 1 minute, or
•
the maximum over the record of the calculated 1 minute average speed (sliding average), if time step of record is smaller.
For cases where T 0<1min, the 3 second gust speed squall is to be considered (See Sec 3, [3.1.3]).
41
NR 493, App 2
b) the wind direction record D(t) is shifted by the difference between a reference direction D r in the record (usually taken as the direction at time of V max) and the reference direction Ds specified for each simulation, thus preserving the variation of wind direction with time, together with the variation of wind speed.
3.2
Note 2: This write: D c(t) = D(t) - D r + Ds
In principle, scanning is to be performed over 360° for the governing (or a reference) element.
2.5
For each of the other elements, scanning is to be performed over a large enough interval to provide the evidence that maximum response has been caught. Generally, the relative direction between any two elements need not exceed 120°.
Current
2.5.1 The design current speed C is to be selected as per
[3.3]. 2.5.2
Actions on floaters
When a current profile is specified, an average speed may be considered for actions on floaters. Note 1: Pending more accurate evaluations, the average current speed may be taken as the average over a depth of: •
1,3 x the vessel draft for ships and barge shaped vessels
•
1,1 x the vessel draft for semi-submersible platforms.
2.5.3
Actions on risers and mooring lines
In shallow and medium water depths, the relevant current profile is to be considered. In deep waters, surface currents and currents over the water column are generally un-correlated, so should be considered in separate sets of design conditions.
3 3.1
Directions
3.2.1 All relevant combinations of the direction of the gov-
erning element (or an element taken as reference) and the relative directions between elements are to be investigated by appropriate scanning.
A scanning step of 15° will be generally sufficient to catch maximum response, taking into account the directional variations of intensities. Note 1: The scanning interval may be reduced, depending on symmetry(ies) of the mooring system (same lines over a flat bottom) and of the Unit (including load coefficients, e.g. for wind), and taking into account the required accuracy (envelope or results in individual lines). Such reduction will however preclude the use of directional data. Note 2: Following the type of mooring (e.g. spread or turret), considerations of e.g. the relative contributions of elements to the total mooring force, or to the line tension (as evidenced by test runs -see also App 1-) may be used to optimise the scanning effort and organise it in appropriate steps, but sh ould not replace such scanning.
3.2.2 Directional sectors are defined for each following
conditions (Extra-tropical, Equatorial and Tropical storm). Due to physical phenomena (Coriolis…), some sectors could be unsymmetrical and are defined for Northern hemisphere in this guidance. Then, they should be inverted in case of study in Southern hemisphere areas.
Metocean design conditions Principles
3.1.1 The design metocean conditions for a specified N-
year return period are defined as combinations of the direction and intensity of waves, wind and current, and of associated parameters. Depending on the climatic condition at site, several sets are defined. In each set, one of the elements is generally governing. For each set, the intensity of elements will be selected with values depending on: • the degree of correlation of extremes, both in intensity and in direction, that are also depending on the climatic conditions at site • the relative directions between elements. Note 1: This is intended to take into account that ex treme values of element intensities may not all result from the same meteorological conditions, nor from the same storm event, nor at the same time within the same event, so will not happen simultaneously, nor necessarily with the same incoming direction.
3.3
Intensities
3.3.1 The intensity of elements is specified from [3.3.2] to
[3.3.6], except otherwise noted, by the return period RP of the value to be used. 3.3.2 For a specified return period N = 100 years of the
combination, RP is specified, in [4] and [5], as: RP
=
R P0 ⋅ 10
r
with RP ≥ 10−2,5, unless otherwise noted (see [3.3.5]), where: RP0
: Reference return period, with RP0 = N = 100 for the governing element, unless otherwise specified
r
: Reduction factor, function of the relative directions between elements (r is always ≤ 0).
3.3.3 When the specified return period N of the combina-
The criteria to select intensities are defined in [4] to [6], for several types of climatic conditions.
tion is lower than 100 years, the values of RP are to be taken as:
These criteria are given for guidance and may need adjustment when more accurate data are available for the site under consideration.
RP
r
=
N ⋅ 10 n with r n
42
3) ⋅ (r 5
r
2)
where r0 is defined by:
Note 2: For a given site, several climatic conditions may be
applicable, depending on the season.
(n
+ + 0 – -----------------------= -----------------------
r0
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=
RP 0
r
=
10 0
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NR 493, App 2
4
3.3.4 For tropical cyclonic conditions (see [6]), a reduction
factor on the N-year value is specified instead of the above formulae.
Extra-tropical conditions
4.1
Applicability
3.3.5 Frequent values of intensities are specified by the fol-
lowing probability of exceedance:
4.1.1 The combinations in [4.2] to [4.5] are applicable to
pe(X) = pasi
areas where metocean conditions are driven by extra-tropical storms during the whole year (e.g. North sea, Mediterranean sea, …) or at some seasons (e.g. winter storms in tropical areas), in which:
pasi = 11% may be considered in the combinations (corresponding to RP = 10 −2,5 in [3.3.2]). Then, r = 0 in any combinations.
• wind driven seas and wind driven current are governing over other components
Note 1: Other value is to be used if defined in the Company's specifications (e.g. p asi = 5% for West Africa).
• sea states are described by an unimodal spectrum and, most often, the strongest sea-states are unimodal wind seas.
3.3.6 When directional data are used, intensity for each
element is taken as the intensity in the geographical sector where that element is lying.
3.4
Some swell is however often present and, in some areas (North West Europe, South West Atlantic, …), a bimodal description is more appropriate: see [4.5].
Operating conditions
3.4.1 The limiting operating conditions may be specified in
different ways (see Sec 3, [9.5]).
4.2
3.4.2 When the limiting conditions for specific operations
4.2.1 Three typical conditions may be defined, as follows:
are infrequent, they can be defined by a return period (not less than one year). Then the combinations of metocean parameters are defined in the same way as (extreme) design conditions, taking into account the specified return period.
Typical design conditions
• wave governed, with the following relative headings: H-V between −45° and +60°, and C-V between −60° and +60°
3.4.3 More frequently occurring conditions are specified
• wind governed, with the following relative headings:
by limiting values on some measurable parameters.
H-V between −45° and +60°, and
Then the combinations of metocean parameters should be established, based on:
C-V between −60° and +60°
• a set of combinations, as applicable to the specific climatic conditions, with however, except those between wind and wind sea, no restriction on the relative direction between elements,
• current governed, with the following relative headings: H-V between −30° and +45°, and C-V between −60° and +90°.
• intensities taken, for each element in a combination, as the lowest of the explicitly specified limiting value, and the value in the N-year design (extreme) combination (with no restriction for relative direction -see [3.3.2]except factor r v for wind and wind sea, where applicable).
Note 1: In a mooring analysis, the wind governed condition may be omitted in most cases, subject to documentation, to the satisfaction of the Society.
4.3
Selection of return periods
• a range of wave period, selected based on a N-year contour, unless otherwise specified in criteria.
4.3.1 Data for the selections of return periods as per [3.3]
Note 1: The same acceptance criteria as for extreme conditions are applicable to operating conditions. Thus, notionally, the contour for operating conditions is defined by applying to the N-year design (extreme) contour the limiting criteria that are explicitly specified (e.g. the combined H S of the sea-state). See Fig 1
However, when directional wave data are used, and unless swell is modelled as per [4.5], a minimum value of H S should be considered to account for occurrence of swell: see [4.4.3].
are given in Tab 1, for N = 100 years.
Table 1 : Extra-tropical conditions - Return period RP 0 - N = 100 years
Type of combination
Waves H
Wind V
Current C
RP0 , in years
r
RP0 , in years
r
RP0 , in years
r
H governed
100
rv + rc
50
rv + rc
10
0,8 r c
V governed
50
rv + rc
100
rv + rc
10
0,8 rc
C governed
10
0,8 (rv + rc)
10
0,8 (r v + rc)
100
rc
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4.4
Reduction factors
4.4.1
4.5
Following combinations are to be added to those given in [4.2]: 4.5.1
Reduction factor r v
The reduction factor r v is given by:
rv
=
rv
=
rv
=
• Swell governed, with the following relative headings between wind-sea W, wind and current:
H-V 1 + ---------- when – 45 ° ≤ H-V < – 15 ° 15 0 when – 15 ° ≤ H-V ≤ +30 ° H-V 2 – ---------- when +30 ° < H-V ≤ +60 ° 15
W-V between −30° and +45°, and C-V between −60° and +60° • Swell with wind and wind sea, with the following relative headings: W-V between −45° and +60°, and
The reduction factor r v is shown in Fig 2. 4.4.2
Conditions with swell
C-V between −60° and +60° • Swell and current, with the following relative headings:
Reduction factor r c
W-V between −30° and +45°, and
The reduction factor r c is given by:
C-V between −60° and +90°. rc
=
0
when C-V ≤ 45 °
rc
=
C -V 1 – ------------- when 45° < C-V ≤ 90 ° 45
Note 1: Swell is assumed here to be independent of the other parameters, both in intensity and in direction, s o any direction is to be considered over 360°, and no reduction is applicable (i.e. r = 0) for the relative direction between swell and other elements. However same direction as in [4.4] above are applicable to W, V and C combinations.
The reduction factor r c is shown in Fig 2. 4.4.3
Notes
• Contours of rv and rc may be adjusted when adequate data of joint occurrence are available. • When a value of current quoted as "simultaneous" (with wind or waves) is defined in the Site specification, the values of C in a combination (wind and wave governed conditions) may be taken as the lowest between the specified value (without reduction for relative direction) and the value obtained by the above criteria for that specific combination. • When directional data are used, and to account for the possible occurrence of some swell that is uncorrelated with wind, HS in any direction should be taken not less than the smallest directional values of H S at the return period RP0 (i.e. without reduction for relative direction) specified in Tab 1 for the subject combination (or another appropriate value).
Note 2: In a mooring analysis, when swell intensity is significantly lower than wind seas, these conditions may be omitted in most cases, subject to docume ntation to the satisfaction of the Society.
4.5.2 Data for the selections of return periods are given in
Tab 2.
5
Equatorial conditions
5.1
Applicability
5.1.1 Climate in equatorial conditions (e.g. West Africa) is
characterised by long distance swells, local winds and currents, all three having distinct sources, thus being almost uncorrelated. In addition, some distinct local events, typically not represented in the statistical distributions, are to be considered (see [5.2.3]).
Figure 2 : Reduction factors r v and rc
rv
rc
-0,00
-0,00
-0,25
-0,25
-0,50
-0,50
-0,75
-0,75
-1,00
-1,00
-1,25
-1,25
-1,50
-1,50
-1,75
-1,75
-2,00 -60˚
-2,00 -45˚
-30˚
-15˚
0˚
+15˚
+30˚
+45˚
+60˚
relative direction H-V
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0˚
+15˚
+30˚
+45˚
+60˚
+75˚
+90˚
relative direction |C-V|
April 2012
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Table 2 : Extra-tropical conditions with swell - Return period RP 0 - N = 100 years
Type of combination
Swell S
Waves W
Wind V
Current C
RP0 (years) or pe
r
RP 0 (years) or pe
r
RP0 (years) or pe
r
RP0 (years) or pe
r
W governed
−
−
100
rv + rc
50
rv + rc
10
0,8 r c
V governed
−
−
50
rv + rc
100
rv + rc
10
0,8 r c
C governed
pasi
−
10
0,8 (r v + rc)
10
0,8 (r v + rc)
100
rc
S governed
100
0
p asi
−
pasi
−
pasi
−
S and V + W
1
0
1
0,6 r v
1
0,6 rv
pasi
−
S and C
1
0
p asi
−
pasi
−
1
0,6 rc
5.2
Typical design conditions
Table 3 : Equatorial conditions Return period RP 0 or pe (in years) for N = 100 years
5.2.1 Three base combinations may be defined as follows:
Type of combination
Swell S
Waves W (1)
Wind V
Current C
S governed
100
−
pasi
pasi
V / W governed
pasi
100
100
p asi
C governed
pasi
pasi
pasi
100
S and V / W
1
1
1
p asi
S and C
1
p asi
pasi
1
C and V / W
p asi
1
1
1
Squall wind
p asi
pasi
100 (2)
pasi
Alternatively, these three combinations can be conservatively merged in a single one.
Local current
pasi
pasi
pasi
100 (2)
5.2.3 Additional combinations include:
(2)
• swell governed • wind governed • current governed. 5.2.2 Three intermediate combinations should be also con-
sidered: • swell and wind • swell and current • current and wind.
• squall wind condition
(1)
5.5
• local current (e.g. surface current) condition.
If present. See [5.5.2]. Following the relevant distribution.
Directions
5.5.1 Owing to lack of correlation, swell, wind (or squall)
tion of swell and wind-sea.
and current (or local current) are to be taken as acting together in any combination of directions, each over all possible directions, and no reduction factor r is applicable (i.e. r = 0 is to be taken in [3.3]).
5.3.2 Swell is often a combination of several independent
5.5.2 The relative direction of wind-sea with wind may be
5.3
Waves and wind
5.3.1 Waves are described in this sub-article as a combina-
swell systems, but the strongest sea states usually show u nimodal swell. Then the swell governed condition could be separated in: • a main swell governed condition (with unimodal swell)
assumed not to exceed 45°. In addition W = 0 (i.e. no wind sea) can be considered when its anticipated direction is falling in a sector in which no wind-sea was observed.
6
Tropical storm conditions
• concomitant swells condition (multimodal). 5.3.3 Winds (other than squalls) are rather weak, and the
higher frequency part of wave spectra, often denominated as "wind seas", is not well correlated with wind.
6.1
Applicability
6.1.1 Extreme conditions in areas affected by tropical storm
Tab 3, for N = 100 years.
(e.g. Gulf of Mexico, South East Asia, North West of Australia) are governed by occasionally passing hurricanes/typhoons, causing strong wind, waves and current, with rapid variations of both intensity and direction over a limited time. In this case, associated values are better defined by a ratio to the specified extreme, and the wave direction is used for reference.
In the combinations, the associated values of non governing parameters may be taken as a "frequent value" (see [3.3.4]).
Directional data should be used with caution. Their derivation needs special care.
Note 1: However, for practicality, wind-sea is hereafter assumed correlated with wind.
5.4
Selection of return periods
5.4.1 Data for the selections of return periods are given in
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6.2
Typical design conditions
6.3.2 Data for factors cH, cV and cC are given in Tab 4.
If needed, factors c H, cV and cC for intermediate situations (C-H between −30° and −60°) may be obtained by interpolation between the H and C combinations.
6.2.1 Three typical conditions may be defined as follows:
• wave governed, with the following relative headings: V-H between −45° and +45°, and
Table 4 : Tropical storm conditions Intensity of the elements
C-H between −30° and +30° • wind governed, with the following relative headings:
Type of combination
Waves cH
Wind cV
Current cC
H governed
1,0
0,9 qv
0,5
V governed
0,9 qv
1,0
0,5
C governed
0,7 qv
0,6 qv
1,0
V-H between −45° and +45°, and C-H between −30° and +30° • current governed, with the following relative headings: V-H between −45° and + 45°, and C-H between −120° and −60°. Intermediate situations between the H governed and the C governed cases (with C-H between −30° and −60°) should be considered if needed. Note 1: In a mooring analysis, the wind governed condition may be omitted in most cases, subject to documentation to the satisfaction of the Society.
6.3.3
Reduction factor q v
The reduction factor q v is given by: qv
=
1
when V-H ≤ 30 °
qv
=
V-H 2 – ------------- when 30 ° < V-H ≤ 45 ° 30
The reduction factor q v is shown in Fig 3. 6.2.2 In addition, conditions for winter/monsoon seasons,
and those for local currents (e.g. eddy currents) are to be separately considered, as defined above, when relevant.
6.3
Figure 3 : Reduction factor q v 1.25
Data for the intensity of the elements
1.00
6.3.1 For each parameter (H, V or C), the intensity X may
be taken as:
v0.75
q
X = cX ⋅ XN 0.50
where: XN
: Intensity at the specified return period N
cX
: Reduction factor to account for both the degree of correlation and the relative direction between elements.
46
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0.25 0
15
30
45
relative direction V-H
April 2012
NR 493, App 3
APPENDIX 3
1
STRUCTURAL STRENGTH CRITERIA
General
1.1
1.2.5 For structures on the Unit end, that may be subject to
Subject
1.1.1 This Appendix is applicable to the steel components
of a mooring system such as: • non standard connection and termination fittings
loads from several adjacent lines, combinations of loads may be derived from mooring analysis. In each of the condition of the mooring system, load combinations are to be categorised as in [1.2.2] above. Several combinations of line loads in each case may be needed to assess strength. 1.2.6 Other loads acting simultaneously as the line loads
are to be considered where applicable (e.g. soil reactions, for anchors). Generally, self weight is negligible and can be omitted.
• anchors • supporting structures in Unit hull or turret • ancillary components. 1.1.2 Guidance is given on structural strength criteria, as a
complement to the criteria specified in Offshore Rules, Part B, Chapter 2 and Chapter 3, and concerning: • design loads
1.3
Elastic design
1.3.1 When assessment of strength is based on elastic anal-
ysis, the strength criteria in Offshore Rules, Part B, Ch 3, Sec 3 are applicable.
• assessment of strength based on non-linear analysis.
1.3.2 The following criteria are to be satisfied:
Fatigue strength and, where relevant, buckling strength are not addressed below and are to be duly considered following the applicable requirements of Offshore Rules and those of the present Note.
where:
σC ≤ 1,1 α Rf
1.1.3
1.2
σC
σa
Design loads
α 1.2.1 As specified in Sec 4 and in Offshore Rules, Part B,
Ch 2, Sec 3, [4.2], the reference load for design of steel components is the specified breaking strength that shall be considered as “load case 3” (accidental), with respect to the strength criteria of Offshore Rules, Part B, Chapter 3.
Rf
and
σa ≤ α Rf
: Equivalent stress (as specified in Part B, Chapter 3, Sec 3 [5.3] of the Offshore Rules), under the design loads as defined in [1.2] : Axial stress, under the same conditions (pure tension case) : Allowable stress factor, as defined in Offshore Rules, Part B, Ch 3, Sec 3, [5.4.2], for the case considered (see [1.2.2]) : Reference stress (as specified in Offshore Rules, Part B, Ch 3, Sec 3 [5.2.1]).
1.3.3 In case of assembly with contact between several ele1.2.2 In addition to the above requirements, the following
design loads are to be considered, as necessary: • design tension TD , in the intact conditions of the mooring system, as a “load case 2” (design) • design line tension TD , in the damaged condition of the mooring system, also as a “load case 2” (design) • design line tension TD , in the transient (line failure) condition of the mooring system, as a “load case 3” (accidental).
ments, non-linear contact analysis may be omitted, provided the distribution of stresses in the body of the element is not sensitive to the distribution of pressure over the contact area. 1.3.4 Local high compressive stresses in contact areas can
be generally ignored, if the geometry ensure confinement of the area, so that shear failure is not foreseeable, and if the above condition is also satisfied.
1.4
Elastic plastic design
1.2.3 The line of action of the design load is generally dic-
1.4.1 In elastic-plastic analysis, a stress-strain relation is
tated by the geometry of the component.
assumed as: σ =Eε for
| σ | ≤ Rf , | ε | ≤ Rf / E
σ = Rf
| ε | ≥ Rf / E
1.2.4 For items fixed to the Unit or to the anchor, the angu-
lar variations resulting from tolerances in system geometry, Unit offset and Unit motions are to be duly considered. Suitable ranges of orientation are to be specified, with consideration of the loads induced in each part of the item.
April 2012
for
The load is applied by increment, until instability, or the onset of large deformations, or a maximum, is observed. Contacts are to be modelled adequately.
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The strength criterion is:
1.5
LD ----- ≤ L P α
1.5.1 In elasto-plastic analysis, the stress-strain relation cor-
responding to the actual type of material is considered. This relation is to be re-scaled so that the yield stress, the ultimate stress, and the elongation at rupture are equal to the minimum guaranteed properties of the material. Analysis is accounting for the effects of large deformations.
where: LD
: Design load
LP
: Load resulting in plastic failure
(analysis does not need to be continued beyond 1,05 L D / α if failure is not observed). 1.4.2 In some cases, the capacity of the structure can be
assessed by assuming one or more plastic hinges at discrete locations, and failure is observed as an instability of the structure. In such case, the strength criterion is, for all hinges: FD ----- ≤ F P α
where: FD
: Internal Force at a plastic hinge, under the design load
FP
: Capacity of the plastic hinge.
Note 1: F D and F P can be a single internal force component (e.g. a plastic moment), or a vector of several components (e.g . axial force and moment) acting together, taking into account a suitable interaction formula.
48
Design based on elasto-plastic analysis
Contacts are to be modelled adequately. The load is applied by increment, until a maximum, or the onset of large deformations, or excessive local strains, is observed. The strength criterion is: βLD --------- ≤ L f α
where: LD : Design load Lf : Load resulting in plastic failure β : Factor to be taken equal to: • 1,05 for line components • 1,15 for on-vessel supporting structure and for anchoring padeyes Note 1: Analysis may be stopped at β LD / α if failure is not observed. Note 2: Elasto-plastic analysis on anchoring device is only allowed for anchoring pad-eyes.
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APPENDIX 4
GEOTECHNICAL CAPACITY OF ANCHORING DEVICES (PARTIAL FACTOR FORMAT)
Symbols TD
: Design tension in line at lug, calculated according to Sec 3, [6]
TP
: Line pretension (see [2.2.1])
F
: Force in line resulting from environmental actions at lug (see [2.2.3])
FS
: Static force at lug (see [2.2.2])
α
: Angle of line at lug (see [2.1.3])
in the following should be accounted for in an appropriate way, such as:
γ p
: Partial load factor for line pretension (see [2.3.1])
• a range is defined and the less favourable value is considered (e.g. for out of plane loading of the anchor)
γ Fs
: Partial load factor for static tension (see [2.3.2])
γ F
: Partial load factor for tension given in Tab 2
C
: Ultimate capacity of the anchoring device (see [3])
2
P’
: Submerged deadweight of the anchoring device (see [3.2.1])
2.1
q
: Generic soil parameter (see [3.1])
ε
: Factor for suction effect (see [3.2.4])
γ M
: Material factor (see [3.1.2])
A
: Model factor (see [4.1])
• intact system
Kα
: Uplift factor (see [4.2]).
• damaged
VLA
: Vertically loaded anchor.
• transient condition, when required (see Sec 3, [9.6]).
1.2
Format
1.2.1 The criteria in this Appendix follow a limit state (par-
tial factors) format, with distinct partial factors for actions and soil properties, and a set of global factors (model factor and safety factor) on the right side of the inequalities in [5]. 1.2.2 The uncertainties on parameters not explicitly quoted
• a suitable partial factor is considered, when a statistical description is possible (e.g. the rate of increase of shear strength with depth).
Actions General
2.1.1 The actions at anchor lugs are to be evaluated for the
possible combinations of metocean parameters and configuration of the system (see Sec 3, [9]), and for the following conditions of the mooring system: • static (intact system)
2.1.2 The actions at anchor lugs, in each of the design con-
1
General
dition to be considered, are defined on the basis of: • the angle α of line at lug
1.1
• the components of the design tension TD at lug.
Scope of application
1.1.1 The present Appendix is addressing the geotechnical
capability of anchoring devices for an offshore permanent mooring, and applies to such devices as suction anchors, drag anchors, VLA’s, clumps and short piles. The criteria in this Appendix are only valid for anchoring devices in adequately known soil profiles and in the absence of detrimental geo-hazard (see Sec 4, [6.2.2]). 1.1.2
Effects associated with creep and cyclic/repeated loading are to be investigated, if anticipated as detrimental. 1.1.3
April 2012
2.1.3 The angle α of line at lug is the angle of line with
respect to horizontal.
2.2 2.2.1
Design tensions Pre-tension
The line pretension Tp is the static tension in the mooring line at lug in the absence of environmental loads. Note 1: T p is including the effect of permanently applied loads such as tensions from risers or export lines attached to the floating body (see Sec 3, [3.2.3]).
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2.2.2
3
Static condition
Capacity
In the static condition, the static force at lug, noted F s , is the environmental permanent force resulting from e.g. a persistent general circulation current, if any.
3.1
FS is given by:
3.1.1
FS = Tm − TP where: Tm
: Mean (static) line tension under permanent metocean actions.
In the absence of specific information, F S may be taken equal to 0. 2.2.3
Dynamic forces
For each condition of the mooring system (intact, damaged, and transient condition when required) the force in line at lug F resulting from environmental actions only (i.e. excluding pretension) is evaluated for both extreme (100-year return period) and operating metocean conditions (1-year return period, if not otherwise specified: see Sec 3, [9.5] and Sec 3, [6]). F is given by:
Ultimate capacity General
The ultimate capacity C of the anchoring device is defined as the ultimate capacity in the direction of the line at lug, as defined by angle α in [2.1.3] above, and is a function of soil strength parameters. The evaluation of capacity is to account for any misverticality of the anchoring device. The ultimate capacity C is to be evaluated considering the main soil parameter q (appropriate shear strength or tan φ) being divided by a material factor γ M. The ultimate capacities are thus noted as C (q / γ M) in the criteria given in [5] below. 3.1.2
Material factor
The values of γ M are given in Tab 3.
F = TD − TP
Table 3 : Material factor γ M
The notations in Tab 1 are used to describe corresponding forces and the associated load factors.
Condition
Table 1 : Dynamic force in line and associated load factor − Notations
Static
γ M (1)
1,4
Intact (Extreme and Operating) Design condition Extreme conditions
Condition of mooring system Intact γ Fe,i
Operating conditions γ Fo,i
2.3
Damage
Damaged
Transient
Transient
Fe,i γ Fe,d
Fe,d γ Fe,t
Fe,t
Fo,i
Fo,d γ Fo,t
Fo,t
γ Fo,d
1,3
(1)
3.2
Partial load factors
γ M may be taken equal to 1,2 for sands.
Components of ultimate capacity
2.3.1 The partial load factor γ p for line pretension is to be
3.2.1
taken equal to 1,15.
The deadweight of the anchoring device P’ is to be taken as the submerged weight in soil.
2.3.2 The partial load factor γ Fs is to be taken equal to 1,25. 2.3.3 The partial load factor γ F for dynamic forces is to be
taken as per Tab 2.
Condition of mooring system Intact
Damaged
Transient
Extreme conditions
γ Fe,i = 1,35
γ Fe,d = 1,4
γ Fe,t = 1,5
Operating conditions
γ Fo,i = 1,25
γ Fo,d = 1,3
γ Fo,t = 1,4
In intact and damage conditions, γ F are for forces evaluated through dynamic analysis (see Sec 3, [2.4]). Note 2: The forces in transient conditions are usually evaluated through quasi-dynamic analysis (see Sec 3, [2.3]). If a dynamic analysis is performed, γ Fe,t and γ Fo,t may be taken as for damaged cases. Note 1:
50
Ultimate capacity C S and C C
The ultimate capacity C is to be evaluated for both static (permanently applied load) and dynamic situations, and are noted respectively C S and CC.
Table 2 : Load factor γ F
Design condition
3.2.2
Deadweight
For suction anchors or similar anchoring devices that may develop such phenomenon, C S and CC are the capacities not considering any suction effect. 3.2.3
Additional capacity C a
For suction anchors or similar devices, an additional ultimate capacity Ca resulting from the development of in-service (normally passive) suction may be taken into account in dynamic situation.
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3.2.4
Factor for suction effect Ca is to be factored by a factor ε, varying from 0 to 1.
4.3
The factor ε is depending on particular soil condition and device, and is to reflect: • the confidence on the development of in-service suction (as proven by experience or through experiments, etc.) • its anticipated mobilisation, specially under dynamic actions.
4.3.1
When the possibility of in-service suction is established, ε may be taken as the ratio of the double amplitude wave frequency load due to waves to the design tension in the situation considered, or may be derived by other appropriate method.
In the case of a structure in close proximity, the safety factors for anchoring devices of line type I is to be increased in accordance with Sec 3, Tab 4 (see notes (3) and (4) of the table). A specific Risk Analysis may be considered to help in defining appropriate factors for a particular situation.
4
Other factors
4.1
4.1.1 The factor A is a model factor. A is to be taken as 0,67.
For drag anchors, depending on experience on the type of anchor for the particular soil conditions and the possibility of gaining additional capacity when more deeper burying, the factor A may be taken as low as 0,55.
4.2
Basic minimum safety factors are specified in [5] below, on the right side of inequalities, for each relevant condition. These factors are for anchoring devices of line type II (see Sec 3, [10.1.1]).
5
Factor A
Safety factors
5.1
Criteria General
5.1.1 The inequalities to be satisfied in each design condi-
tion are given in Tab 4 below. The set of inequalities is to be simultaneously satisfied, however those for transient conditions need not be considered when transient analysis is not applicable (see Sec 3, [9.6])
Uplift factor
4.2.1 The uplift factor K α is to be taken as:
Kα = 1 + 0,33 sin 2α
Note 1: The criteria given in the present [5] are checking formats, not equilibrium equations.
Where α is taken as defined in [2.1.3].
Table 4 : Design criteria
Condition of mooring system Static
Extreme conditions
Operating conditions C CS ( q/ γ M ) + 0, 9P ′ sin α -------------------------------------------------------- ≥ 2, 2AK α γ P T P + γ FS F S
Intact
C C ( q/ γ M ) + ε C a ( q/ γ M ) + 0, 9P ′ sin α -------------------------------------------------------------------------------------- ≥ 1, 15 AK α γ P T P + γ Fe , i Fe, i
C C ( q/ γ M ) + ε C a ( q/ γ M ) + 0, 9P ′ sin α -------------------------------------------------------------------------------------- ≥ 1, 45 AK α γ P T P + γ Fo , i Fo, i
Damaged
C C ( q/ γ M ) + ε C a ( q/ γ M ) + 0, 9P ′ sin α -------------------------------------------------------------------------------------- ≥ 1, 0AK α γ P T P + γ Fe , d F e, d
C C ( q/ γ M ) + ε C a ( q/ γ M ) + 0, 9P ′ sin α ------------------------------------------------------------------------------------- ≥ 1, 3AK α γ P T P + γ Fo , d Fo, d
Transient
C C ( q/ γ M ) + ε C a ( q/ γ M ) + 0, 9P ′ sin α -------------------------------------------------------------------------------------- ≥ 0, 9AK α γ P T P + γ Fe , t F e, t
C C ( q/ γ M ) + ε C a ( q/ γ M ) + 0, 9P ′ sin α -------------------------------------------------------------------------------------- ≥ 1, 15 AK α γ P T P + γ Fo , t Fo, t
April 2012
Bureau Veritas
51
