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API RP 2SK 4th Edition - An Updated Stationkeeping Standard for the Global
Offshore Environment
Hongbo Shu, Insight Offshore Consulting, LLC, Chevron Energy Technology Company; Aifeng Yao, Kai-Tung Ma,
and Wei Ma, Chevron Energy Technology Company; Jonathan Miller, Miller Technical Consulting
Copyright 2018, Offshore Technology Conference
This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 30 April–3 May 2018.
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The American Petroleum Institute Recommended Practice on Design and Analysis of Stationkeeping
Systems for Floating Structures (API RP 2SK) provides guidance on the best practices for floating structure
stationkeeping system engineering so they will remain safely within their designed excursion limits. By so
doing, the engineer ensures the safety of the floating structures and the integrity of riser systems connected
to the exploratory and/or producing wells. This API standard provides the comprehensive guideline for
designing stationkeeping systems and has been cited in well over 100 technical papers worldwide. API
RP 2SK is referenced by Code of Federal Regulations Title 46 (46 CFR Part 250) for oil and gas related
operations in the US Outer Continental Shelf.
Since its 3rd edition was published in 2005, the industry has collected significant data and learnings from
offshore mooring operations, especially from the experience in the hurricane seasons in 2004, 2005, and
2008. Although much of these learnings have been captured in the Appendices (e.g. Appendices H, CH
and K, May 2008), it is difficult for end users to quickly understand and implement the requirements of
the standard when they are interspersed with informative recommendations in a document that is over 250
pages long. To be consistent with the recent formatting style of international standards, this 4th edition of
API RP 2SK has sorted all requirements into the "normative" section at the front, while recommendations
are organized in the corresponding "informative" part in the Annex. In addition, regional requirements or
considerations have also been included in annexes to make this API standard globally applicable.
On the technical front, the following updates are included in this edition of API RP 2SK:
1. Design limit states are revised to be aligned with the latest ISO 19900 DIS (2018) [10].
2. New normative guidelines for mooring design Robustness Check have been added.
3. Design criteria for MODU moorings has been restructured, encouraging risk-based design criteria
selection (QRA). Drag anchor design FOS has also been updated.
4. Provides specific guidance for Response Based Analysis method.
5. Developed new informative guidance on how to conduct chain OPB/IPB and Tension-Tension
fatigue analysis.
6. Initiated design criteria for wire rope bend-over sheaves.
7. Initiated new design considerations against mooring line trenching on sea floor.
8. Updated corrosion allowance ranges, selecting criteria based on latest industry data and findings.
9. Updated guidance on how to include vortex induced motions (VIM) effects in mooring design.
10.Added new recommendations to include mooring system life cycle considerations (e.g. installation)
in design stage.
11.Thruster-assisted mooring (TAM) design criteria in the North Sea region updated per UK OIS 2013
12.Regional guide for cyclonic region aligned with APPEA MODU Mooring Guide (2016) [9].
This paper introduces the newly updated API RP 2SK, highlights the updated or new requirements and
guidance notes, compares the structure of the 3rd and 4th editions, and API/ISO stationkeeping standards,
helps users get familiar with the new edition of API RP 2SK to be published in 2018.
API RP 2SK is used by the offshore industry worldwide for stationkeeping design of offshore floating
drilling and production platforms as well as other floating offshore installations such as construction vessels,
floating hotels, floating wind power platforms. It has also served as the base document for a few industry
standards, such as APPEA guideline for MODU mooring in Australia [9] and ISO 19901-7[11]. The current
structure of the API standards related to technical topics of stationkeeping design is illustrated in Figure
1 below.
Figure 1—The current structure of API standards related to key areas of stationkeeping systems (as of 2017).
For historical reasons, the specifications or guidelines for some of the mooring components (such as
anchors or underwater-disconnectable mooring connectors) are included in the appendices of the API RP
2SK. The testing guideline and specification for fiber mooring ropes are included as part of the API RP 2SM
[2]. In the ISO side, ISO 19901-7:2013 [11] combines the design analysis guideline for both steel and fiber
rope mooring systems which were derived from API RP 2SK 3rd edition [1] and API RP 2SM 1st edition, but
adds a standalone specification (ISO 18692: 2007) for fiber mooring ropes. API and ISO jointly published
standards of metocean criteria [5], and geotechnical design [4]. However, the joint development work is
currently on hold. In 2017, ISO published its 1st edition of mooring chain specification – ISO 20438 [30].
In early 2018, ISO 19900 DIS[10] was released which sets the general requirement and frame work for
other standards on offshore structures to follow. Figure 2 shows the current structure of ISO stationkeeping
standards in comparison with API's in Figure 1.
Figure 2—The current structure of ISO standards related to key areas of stationkeeping systems (as of 2017).
Ideally, a design analysis standard should only include the requirement (Normative or Informative)
for designing a system, which will then be supported by a suite of component specifications and testing
requirements for the system, rather than mixing the component specifications and testing standards in a
design standard. The benefits of separating the design requirements from the component's specification/
testing requirement include allowing the different content to be updated in a timely manner as new technical
advances become known and widely accepted in the industry, as well as adding clarity to the natural
boundaries among system-vs-components and different components in the system. This philosophy was
supported by the industry communities on both API and ISO sides, but due to time and resource limitations,
the work of restructuring the API stationkeeping standards in accordance with the above philosophy was
deferred to the future.
The feedback from the industry after using the 3rd edition of API RP 2SK since 2005 includes that
although the document contains a lot of important and useful information, it is difficult for a user, especially
a new engineer, to quickly figure out what are mandatory and what are optional requirements when it comes
to designing a stationkeeping system. In the 4th edition of API RP2SK, all mandatory requirements are
included in the Normative Part while most of the guidance notes, optional, or regional requirements are
in the informative part of the standard. Only limited informative materials are included in the normative
to keep the continuity in discussion and to give users proper reference. This document structure provides
a clear distinction between what is a mandatory requirement, and what are optional considerations for the
design of either a permanent or a mobile stationkeeping system, which is consistent with new API standard
guideline and ISO standard structure. During this restructuring, the editing panel also moved and updated
the illustrative materials such as new design guidelines and analysis examples into the Informative part of
the standard to preserve the educational value of the standard for new engineers.
As it became widely accepted by the industry since its introduction in 2008, the risk-based design criteria
selection for both mobile and permanent mooring systems found in Appendix K has been elevated to the
normative requirements. In this edition of the RP2SK, more specific guidance notes have been provided to
clarify the minimum design criteria and requirements [20].
It is also recognized that the mooring integrity should be managed during the life cycle of the mooring
system from its design stage. In the early stages of revising RP2SK, the topic of mooring integrity
management (MIM) was given a separate section of its own. Later, the topic of MIM was elevated into its
own separate recommended practice [8] [23]. Therefore, MIM requirement at design stage is removed from
this edition of RP2SK, and users are referred to the API RP 2MIM to be published in 2018. On another
note, API RP2I (2008) needs to be updated to include inspection guidelines for permanent moorings.
Recent publications [16] [17] noted that the failure rate of mooring lines is higher than design expectations
for other offshore structure components. The response from the industry tends to increase the design factor
of safety and/or design criteria in ULS. These measures all led to using stronger and larger mooring
components. However, the mooring line failure rate has remained stubbornly unchanged since 1990s. The
industry gradually realized that just using larger components isn't the right solution for reducing the mooring
line failure rate. The reliability of a stationkeeping system can only be improved when the quality assurance
is ensured consistently in every step of the way from design to installation. This edition of the API RP
2SK has been updated with clear guidance for the users/stakeholders to understand how to carry out the
design to meet the intent, and to test the sensitivity of their design's performance to the perturbations in
the design conditions.
This edition of API RP 2SK also initiated coverage and added new guidance notes on several important
technical developments in the offshore industry since 2008. For example, robustness design check, mooring
chain out of plane/in-plane bending (OPB/IPB) fatigue design, steel wire over the sheave bending fatigue
design, the impact of vortex-induced motions of a floating structure on mooring design considerations,
updated corrosion and wear/abrasion allowance based on the local water conditions, and mooring system
design considerations against taut-line trenching on the seafloor. In the following sections, several
noteworthy technical updates will be highlighted and discussed in more detail.
Design Limit States
To give more consistent requirement for designing offshore structures, both API and ISO organizations
are changing the standards structure to establish the design frame work and general requirement for oil
& gas industry's floating offshore structures in a hierarchically elevated standard, such as ISO 19900
DIS:2018[10], whereas the sub-system design standard (such as the RP2SK) will be aligned to provide
supporting and more specific/detailed guidance on how to carry out the design of a sub-system (such as the
mooring system) of the floating offshore structure. To that end, this edition of API RP2SK also restructured
design considerations into four Limit States to be aligned with those of ISO 19900 DIS:2018 [10], and to
be consistent with ISO 19901-7 DIS:2017[28], see Table 1 below:
Table 1—Comparison of the limit states for ISO 19900 DIS (2018), API RP 2SK 4th ed. and ISO 19901-7 DIS (2017).
In the 4th edition of RP2SK, the ULS for mooring system design includes both intact and one-line damaged
(redundancy) design conditions. The SLS includes operational design situations, which will define the
operational limit conditions for drilling, production and offloading, as well as operational considerations
when any mooring line is broken or any thruster has failed. In ISO 19900 DIS, ALS for offshore structures
address complete loss of integrity of the structure, or of a vital part of the structure, such as loss of
stationkeeping (free drifting). Therefore, there is no ALS normative design requirement for stationkeeping
in this standard except for that requirement on disconnectable FPSO systems.
Design Robustness Check
In the Appendix K of API RP2SK 3rd edition [1] [15], the robustness check was presented in the form of
weak point analysis. The objective was to determine the probable failure mode of the mooring system, to aid
the risk assessment and mitigation strategies at the design stage. In the offshore industry, it is now a common
practice to check critical mooring design to a longer return period than that specified in ULS requirements
(i.e. a "robustness check"). In ISO 19900 DIS (2018) [10], the robustness check for offshore structures has
been elevated to a normative requirement.
In the 4th edition of RP2SK, the robustness check is broadly defined as analyzing a stationkeeping system's
survivability in exposure to deviations of identifiable critical design conditions/parameters. The goal is to
have inherent safe design and to prevent catastrophic system failure in the event of any single point of failure.
More specifically, robustness checks should examine a stationkeeping system's survivability in exposure
to greater loading in a sea state higher than that of ULS; or in unfavorable heading combinations of
winds, waves, or currents; or in the event of floating structure damage such as accidental flooding of
a compartment, exposure to greater stress due to higher than anticipated corrosion/wear rates or pitting;
exposure to abnormal fatigue mechanism (such as an unusually strong loop current event in early service
life of a Spar mooring system). Checking the survival of stationkeeping system against these conceivable
scenarios is consistent with ISO 19900 DIS normative requirement for robustness check of an offshore
structure design.
Furthermore, during mooring system robustness check, the foundation structure of the on-board mooring
hardware (fairleads, chain jacks, winches, and chain stoppers) should be verified to be able to meet the
structural design criteria of API RP2A [32] against the corresponding greater loadings in the robustness
check conditions.
It is recommended that permanent moorings (especially for manned floating platforms) be designed with
sufficient reserve capacity to withstand the higher design load in the perturbation of ULS sea states without
the complete loss of a stationkeeping system, therefore the floating platform connected to it. Return periods
specified for robustness check design situations should be selected at least one order of magnitude greater
than that used for ULS to show the system's response variation. This is consistent with the recommendation
in Clause 5 of ISO 19900 DIS [10], where the return period for ALS is recommended from 1,000 to 10,000
years. The selection of return period for robustness check and the associated design acceptance criteria shall
be the responsibility of the operator of the floating structure, but the minimum safety factor for line tension
should not be less than 1.0.
For disconnectable mooring systems, if the joint probability of occurrence of the accidental/abnormal
environmental event combined with the failure to disconnect is less than 10-4 per annum, an ALS design
check is not required. This is consistent with ISO19901-7 [11] [28]. Therefore, robustness check for such
a load case is not required either.
Summary of Unified OPB/IPB/TT Fatigue Design Methodology and Guidance
Out-of-plane bending (OPB) fatigue of the mooring chain is a newly discovered fatigue mechanism that can
significantly reduce the service life of a mooring line [12] [20]. Although the three OPB induced failures
[16] [20] all appeared to be the consequence of improper design of geometric restriction on the chain links
near the top connections, the industry still doesn't have any widely accepted or effective screening criteria
to eliminate the OPB fatigue from any mooring system design considerations. Therefore, OPB and its
associated In-Plane-Bending (IPB) fatigue should be addressed in the design of a mooring system unless it
can be shown that OPB/IPB fatigue is not a controlling design factor for the system under consideration.
Chain OPB fatigue analysis is similar to analysis and design of a structural component. The global
analysis used for OPB fatigue analysis is typically performed in time domain. In addition to the general
requirements for global analysis in the RP2SK, the numerical model of the floater and mooring lines needs
to be able to capture the relative angle between the mooring line and the floater to which it is attached, both
in the vertical plane and in the horizontal plane. The input parameters for the OPB analysis can be obtained
from full scale testing or from FEA of the chain links, considering the chain link geometry, the mechanical
properties of the bar material and the magnitude of the proof load that will be applied during manufacturing.
Furthermore, the interaction between the chain links and the top connection as well as the response of the
top connection to rotation need to be considered. If an articulated top connection is used, care should be
taken to model the proper break out moment. Typically, a dual axial articulated top connection is better than
a single axial design against OPB fatigue.
OPB/IPB fatigue damage can be calculated following the hotspot method. For this purpose, the B1 SN
curves in Table 2 (DNV RP C203 [33]) are recommended. Other SN curves may be used by the designer
provided that the SN curve is developed using sufficient amount of full scale OPB fatigue test data. OPB
fatigue safety factor is a function of the SN curve used in estimation of fatigue damage. Preliminarily, the
following factors of safety are recommended: for SN curves with slope of 3.0 the OPB factor of safety is
3.0, and for SN curves with a slope larger than 3.0 the OPB factor of safety is 5.0.
Table 2—B1 SN Curves
In the traditional mooring fatigue analysis, tension-tension (TT) fatigue is analyzed based on tension
loading diagram and compared against the TN curve. Since tension load and bending load are related,
and the tensiontension fatigue can be easily converted to be analyzed in stress domain, it is, therefore,
proposed that the chain fatigue analysis can be combined into a "unified fatigue analysis" and compared
against a select SN curve for estimating total fatigue damage. Toward that end, the timeseries of tension, the
primary and secondary bending moment components are used to calculate the nominal tensile, OPB, and
IPB stress components in the affected links using the moments of area of the chain link. In the case of free
corrosion, the corroded chain diameter is used for calculation of chain moments of area. The total stress at
OPB hotspots are then calculated by applying the appropriate stress concentration factors on the nominal
stress components. In combining the stress components, attention must be given to the phasing between the
stress components. There are four OPB hotspots on a chain link that could have different combinations of
OPB and IPB. Specifically, the total stress time series at each OPB hotspot can be estimated from
Note that the hot spots of tension-tension fatigue are different from those of OPB hotspots, as shown
in Figure 3. However, the total stress at the TT hotspots can be assembled similarly provided that the
corresponding SCF for each stress component at the hot spot being analyzed is determined beforehand.
Finally, rain flow cycle counting is applied on the total stress timeseries to develop the stress range histogram
of each sea state. The long-term stress range histogram is developed from the stress range histogram of
each sea state and the corresponding probability of occurrence of the sea state. The total fatigue life of the
corresponding mooring chain links can then be estimated.
Figure 3—Hot spot locations are distinctly different for OPB loading (left) and TT loading (right)
Revised Risk-Based Design Criteria for MODU Mooring
Mobile or temporary moorings stay at one location for a short term (typically a year or less), compared to
tens of years for permanent moorings on production facilities. Despite the exposure time to the environment
is relatively shorter, the annual failure rate of mobile mooring lines has been seen to be on the order of 10-2
which is about one order of magnitude higher than that of a permanent mooring line [20]. The root cause
analysis for these mobile mooring line failures indicated that improving reliability of MODU moorings
may be achieved through a better design and better handling of mooring hardware. Aiming to improve the
reliability of temporary moorings such as those used by MODUs (Mobile Offshore Drilling Units), the new
RP2SK streamlined the design criteria for a mobile mooring. There appears to be a lack of clear guidance on
designing a mobile mooring system to a proper return period in Appendix K in the previous version (revision
3). The gap is prominent especially for moorings in tropical cyclone regions, also known as hurricane or
typhoon areas. Previous version does not have a clear guidance on what return period shall be used as a
minimum to account for the risk associated with proximity/distance and failure consequence. Revision 4 of
RP2SK updated the design criteria by providing a clearer guidance. It recommends minimum return periods
to be used, and specifies when a quantitative risk assessment (QRA) should be performed to justify the
design criteria for any region with tropical cyclones.
The guidance on selecting design criteria uses Appendix K of the 3rd edition API RP2SK as a basis,
and added some refinement and improvement to aid the users. There are two key variables that need to be
assessed to determine the return period for a MODU mooring at a specific site [20]:
Distance of Proximity – the distance from the MODU under consideration to any other surface
and subsea infrastructure.
Production throughput of nearby facilities – the production rates (oil and gas) of the nearby surface
production facility or flow rates of pipelines that could be in the path of a dragging mooring line.
This approach provides a rational basis for QRA/criteria selection, and maintains consistency with
Appendix K of the 3rd edition RP2SK. Additionally, the revision extends its application from Gulf of Mexico
(GOM) to any regions worldwide that are subject to tropical cyclones; whereas Appendix K was only
applicable to GOM. Guidance on performing a QRA is also provided, and the aspects on how to produce
trustworthy results are addressed.
Update to the Corrosion and Wear Allowance of Mooring Chain
Protection against corrosion and wear of permanent mooring chain is usually provided by increasing the
chain diameter based on the targeted service years. Figure 4 includes examples of more severe than expected
splash zone corrosion in tropical environment that resulted in premature replacement of top chains. Revision
4 of RP2SK has incorporated latest findings on corrosion and wear from recent joint industry researches,
such as SCORCH and DeepStar MAC JIPs [13] [14] [21] [22]. Based on those findings, it recommends that
the diameter increase shall be determined by a site-specific assessment dependent upon several parameters,
e.g. level of dissolved nitrogen, water temperature, water salinity, level of dissolved oxygen, splash zone
action, and water particle velocity.
Figure 4—Examples of severe splash zone corrosion prompts the need to update corrosion allowance
Typical values of corrosion and wear allowance recommended in the 4th edition. of the API RP 2SK are
preliminarily specified as follows:
0.4 mm to 1.0 mm per year of the design service life, for those parts of a mooring line in the splash
zone or zone of hard-bottom sea floor contact,
0.1 mm to 0.4 mm per year of the design service life, for the rest of the mooring line.
If there is evidence that corrosion rates experienced exceed 1.0 mm per year (site specific data),
more conservative corrosion allowances should be considered.
It should be noted that the corrosion and wear allowance recommended for permanent mooring chain is
intended for defending the long-term general corrosion (aka uniform corrosion). Field observations of used
mooring chains have indicated that the general material loss experienced by individual steel chain links
could vary along the body of a link, such as more severe metal loss at the contact zone with significant
interlink motions compared to that at the straight section of the link. In addition, extensive local pitting
often in the form of elliptical pits have been founded on chain links near the sea surface, especially from the
mooring systems installed in the tropical waters. The pit depth growth rate could significantly outpace the
general corrosion and wear allowance of the links at the same water depth. However, the current knowledge
and experience in the mooring industry is not sufficient enough to develop more specific guidance on local
pitting allowance for offshore mooring chains. As such, mooring designers and offshore facility operators
should exercise their discretion when it comes to the selection of chain corrosion and wear allowance and
the long-term mooring integrity management for a specific stationkeeping system under development. The
prior experience in the rate of corrosion or wear from the existing mooring installations in the same region
should provide the best guidance on how to set proper corrosion/wear allowance for new designs unless
new counter measures with proven results are deployed.
VIM considerations in mooring system design
Floating structures comprised of cylindrical structural members such as spars and multi-column platforms
(i.e. semi-submersibles and TLPs) can be susceptible to Vortex Induced Motions (VIM) when exposed to
ocean currents. VIM was first reported for classical spars some 15-20 years ago, leading to the development
of Appendixes H and CH in the 3rd revision. Since then VIM has been also reported on several semisubmersible production platforms in the GOM.
VIM of the host structure is cyclic by nature and may contribute to excessive fatigue damage of the
mooring system. Model testing has been the primary tool for VIM prediction at the design stage. The
confidence in model test results, however, relies on how scaling effects, mooring system stiffness, external
damping contribution from mooring lines and risers, current profiles and turbulence effects, and hull
appurtenances are understood and properly incorporated in the model test. Most of the VIM model tests to
date were performed in a towing tank using a scaled model with a four-point linear spring system to simulate
the mooring and riser stiffness. This practice, while simple in the model testing design and execution,
has been confirmed as a plausible cause for the discrepancy between model scale VIM test data and field
measurements for some deep draft semis. It has been shown by the field measurements, model tests and
CFD studies that the mooring- and riser-induced damping significantly reduces the VIM amplitude as well
as the range of velocities over which lock-in occurs [24] [25]. The importance of including mooring and
riser damping in a VIM model test and potential means of inclusion are discussed in the latest revision.
With the technological advancements in computational power, the use of Computation Fluid Dynamics
(CFD) for VIM design and analysis has become a viable option to predict VIM performance. High-fidelity
CFD has been used to produce accurate VIM predictions matching the corresponding model test predictions
and/or field measurements for several deep draft semi-submersibles [26] [27]. CFD analysis can account
for effects such as scale, mooring and riser damping, current profile, non-linear mooring system stiffness
etc. that are typically ignored or cannot be easily modeled in a tow tank test. Additionally, it can provide
a detailed picture of the overall flow around the floating structure that is otherwise difficult to measure in
a model scale experimental setup. CFD and model testing are not mutually exclusive. A CFD study can
be conducted to predict the VIM behavior and to provide design curves, after the CFD model is validated
by a tow tank test. Guidance on how to use CFD to predict VIM has been incorporated into Revision 4
of API RP 2SK.
Design with project life-cycle in mind
The design capability of a mooring system is only as good as what can be achieved in the installation. Before
a mooring system design is finalized, the designer should conduct a constructability review of the mooring
system with the key stakeholders from fabrication, transportation, installation, site geotechnical survey, and
project management. This design review cycle would allow the mooring designer to gather and verify all
construction related restrictions for the mooring system, and to adjust the design to meet the design goals
within the site-specific restrictions. The designer and the stakeholders together should also define and agree
on the acceptable dimensional tolerances in the mooring component fabrication and system installation.
The final design analysis cycle should verify that the cumulative effect of the dimensional tolerance will
not cause problem for the system installation or hook-up, or to cause the mooring system to fail to meet any
design targets such as extreme loading limit, platform offset limit, or fatigue performance. This edition of
the RP2SK provides guidance on the following areas:
Mooring system installation considerations during design stage,
Mooring line test loading requirement,
Post installation as-built survey and establishment of as-built capacity,
In service mooring integrity monitoring.
The industry trend has been evolving in the direction of integrating requirement of installation,
monitoring, maintenance and replacement/removal in the early stage of design. When the industry common
practice in this direction becomes clear, API RP2SK shall be revised again to include more specific
(normative) guidelines based on industry's best practice.
Concluding remarks
API RP 2SK is the industry's minimum standard for design and analysis of a floating structure's
stationkeeping system. It is referenced by the US regulatory requirement for offshore structures (CFR 46).
it is fitting for this standard to bring the stationkeeping system's life-cycle reliability considerations to the
attention of the floating system designers and other stakeholders (project management, RCS and regulators)
alike at the earliest stage of an offshore project. This is because that the proper design of the safety critical
stationkeeping system is a key step in delivering a safe and reliable floating structure after concept selection.
The industry experience shows that the surest route to improve stationkeeping system's reliability is to
carry out all work in consistent quality for all steps of implementing such a system, from system design/
manufacturing/handling/integration, to system installation/hook-up/maintenance. This edition of the API
RP2SK has been updated with that goal in mind.
The many changes implemented in the 4th edition RP2SK have made it largely consistent with the
industry's high-level standards and parallel standards. The efforts from both API and ISO editing panels
had resolved major discrepancies in the API RP2SK and ISO 19901-7 in their new editions. Future efforts
should be devoted towards combining the two stationkeeping standards into one or perhaps jointly develop
the next generation code. It is understood that there are still higher-level issues to be resolved before the
standards can be jointly developed. Meantime, the users of API RP2SK will finally have an updated standard
since 2005.
The 4th edition of API RP2SK included updated guidance notes on many important technical topics related
to the design of stationkeeping systems, and initiated coverage for regional requirement such as the Atlantic
North seas, cyclonic environment, and ocean conditions where extreme low temperature and ice-loading
must be considered. As the industry accumulates more data from field experience and improves design
practices, some of these informative guidance notes can be revised and elevated into the normative sections
to help the designers achieve the goal of ensuring more robust stationkeeping system for a floating structure
in any environment worldwide.
The authors would like to acknowledge the support of their respective companies and industry colleagues
in producing this paper. We wish to acknowledge the contributions and comments made by Aimin Wang
of Exmar, Pedro Vargas of Chevron, Yongyan Wu of Aker Solutions, David Petruska and Prudence Chen
of BP, Amir Izadparast of SOFEC, Caspar Hyel of Shell, Jun Zou and Arun Antony of Houston Offshore
Engineering, Sue Wang of ABS, Srinivas Vishnubhotla of DNV, David Smith of ExxonMobil, Tom Kwan of
Kwan Engineering Services. The views expressed herein include a collation of facts and opinions provided
by the authors and therefore do not reflect the opinions of any one author or his company.
American Petroleum Institute
Draft International Standard
Factor of Safety
International Organization for Standardization
Join Industry Project
Mooring Against Corrosion (a DeepStar JIP)
Mobile Offshore Drilling Unit
Recognized Class Societies
Quantitative Risk Analysis
Seawater Corrosion of Steel Wire Rope and Chain (JIP)
Stress Concentration Factor
Thruster Assisted Mooring
Vortex Induced Motions
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API RP 2SM, "Recommended Practice for Design, Manufacturing, and Maintenance of Synthetic
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API RP 2I, "Recommended Practice for In-Service Inspection of Mooring Hardware for Floating
Structures", 3rd ed., April 2008.
API RP 2GEO, "Geotechnical and Foundation Design Considerations", 1st ed. 2011.
API RP 2MET, "Derivation of Metocean Design and Operating Conditions", 1st ed. 2014.
API Spec 2F, "Specification for Mooring Chain", 6th ed. 1997.
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units", 2nd ed., May 1, 2013.
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Offshore Technology Conference, OTC 23012, May 2012.
J. Rosen, A. Potts, E. Fontaine, K. Ma, R. Chaplin, W. Storesund, "SCORCH JIP - Feedback
from Field Recovered Mooring Wire Ropes", OTC 25282, Offshore Technology Conference,
May 2014.
ABS Consulting, "Gulf of Mexico MODU Mooring Reliability JIP", Managed by ABS
Consulting, 2005.
16. K. Ma, A. Duggal, P. Smedley, D. L'Hostis, and H. Shu, "A Historical Review on Integrity Issues
of Permanent Mooring Systems", OTC 24025, Offshore Technology Conference, May 2013.
17. P. Smedley, & D. Petruska, "Comparison of Global Design Requirements and Failure Rates
for Industry Long Term Mooring Systems", Proceedings of the Offshore Structural Reliability
Conference, Houston, TX, September 2014.
18. UK HSE Executive, Offshore Information Sheet, Nov. 2013.
19. K. Ma, R. Garrity, K. Longridge, H. Shu, and A. Yao, and T. Kwan, "Improving Reliability of
MODU Mooring Systems through Better Design Standards and Practices", OTC 27697, OTC
Conference, May 2017.
20. A. Izadparast, C. Heyl, K. MA, P. Vargas, and J. Zou, "Guidance for Assessing Out-Of-Plane
Bending Fatigue on Chain Used in Permanent Mooring Systems", Proceedings of the 23rd
Offshore Symposium, Society of Naval Architects and Marine Engineers (SNAME), Houston,
February 2018.
21. E. Fontaine, J. Rosen, A. Potts, K. Ma, R. Melchers, "SCORCH JIP - Feedback on MIC and
Pitting Corrosion from Field Recovered Mooring Chain Links", OTC 25234, OTC Conference,
May 2014.
22. D. Witt, K. Ma, T. Lee, C. Gaylarde, S. Celikkol, Z. Makama, I. Beech, "Field Studies of
Microbiologically Influenced Corrosion of Mooring Chains", OTC 27142. OTC Conference,
May 2016.
23. C. Carra, T. Lee, K. Ma, A. Phadke, D. Laskowski, G. Kusinski, "Towards API RP 2MIM DeepStar Guidelines for Risk Based Mooring Integrity Management", Deepwater Offshore
Technology, Oct. 2015.
24. Irani, M., Jennings, T., Geyer, J., Krueger, E., "Some Aspects of Vortex Induced Motions of a
Multi-Column Floater", Proceedings 34th International Conference on Ocean, Offshore and
Arctic Engineering, St. John's, Newfoundland, Canada, 2015.
25. Sterenborg, J., Koop, A., de Wilde, J., Vinayan, V., Antony, A., Halkyard, J., "Model Test
Investigation of the Influence of Damping on the Vortex Induced Motions of Deep Draft
Semi-Submersibles Using a Novel Active Damping Device", Proceedings 35th International
Conference on Ocean, Offshore and Arctic Engineering, Busan, South Korea, 2016.
26. Kim, S. J., Spernjak, D., Holmes, S., Vinayan, V., Antony, A., "Vortex-Induced Motion
of Floating Structures: CFD Sensitivity Considerations of Turbulence Model and Mesh
Refinement", Proceedings 34th International Conference on Ocean, Offshore and Arctic
Engineering, St. John, Canada, 2015.
27. Wu, G., Ma, W., Kramer, M., Kim, J., Jang, H., O'Sullivan, J., "Vortex Induced Motions of a
Column Stabilized Floater, Part II: CFD Benchmark and Prediction", DOT-2014.
28. ISO 19901-7, "Petroleum and natural gas industries - Specific requirements for offshore
structures - Part 7: Stationkeeping systems for floating offshore structures and mobile offshore
units", DIS, 3rd ed., 2017.
29. ISO 18692, "Fiber ropes for offshore stationkeeping – Polyester", 1st Edition, 2007
30. ISO 20438, "Ships and Marine Technology – Offshore mooring chains", 1st Edition, 2017.
31. ISO 10425, "Steel wire ropes for the petroleum and natural gas industries—Minimum
requirements and terms for acceptance", 2nd Edition, 2003. This is the same as API SPEC 9A,
25th edition, 2004.
32. API RP2A, "Recommended Practice for Planning, Designing and Constructing Fixed Offshore
Platforms—Working Stress Design", 21st Edition, 2000, Errata and supplement 2005.
33. DNV RP-C203, "Fatigue Design of Offshore Steel Structures", 2011.