ISO/TR 13637:1997

Petroleum and natural gas industries - Mooring of mobile offshore drilling units (MODUS) - Design and analysis

Industries du pétrole et du gaz naturel — Amarrage d'unités mobiles de forage en mer — Conception et analyse

General Information

• Status: Withdrawn
• Publication Date: 10-Dec-1997
• Withdrawal Date: 10-Dec-1997
• ICS: 75.180.10 - Exploratory, drilling and extraction equipment
• Technical Committee: ISO/TC 67/SC 7 - Offshore structures
• Drafting Committee: ISO/TC 67/SC 7/WG 5 - Floating systems
• Current Stage: 9599 - Withdrawal of International Standard
• Start Date: 07-Dec-2005
• Completion Date: 13-Dec-2025

Relations

• Revised: ISO 19901-7:2005 - Petroleum and natural gas industries - Specific requirements for offshore structures - Part 7: Stationkeeping systems for floating offshore structures and mobile offshore units
• Effective Date: 15-Apr-2008

Standards Content (Sample)

ISOITR
TECHNICAL
REPORT
First edition
Petroleum and natural gas industries -
Mooring of mobile offshore drilling units
Design and analysis
(MODUS) -
Industries du p&role et du gaz nature/ - Amarrage d’uniths mobiles de
forage en mer - Conception et analyse
Reference number
ISOTTR 13637:1997(E)
ISOTTR 13637:1997(E)
Foreword
IS0 (the International Organization for Standardization) is a worldwide
federation of national standards bodies (IS0 member bodies). The work of
preparing International Standards is normally carried out through IS0
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a technical committee has been established has the right to be represented
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collaborates closely with the International Electrotechnical Commission
(IEC) on all matters of electrotechnical standardization.
The main task of technical committees is to prepare International
Standards, but in exceptional circumstances a technical committee may
propose the publication of a Technical Report of one of the following types:
- type 1, when the required support cannot be obtained for the
publication of an International Standard, despite repeated efforts;
- type 2, when the subject is still under technical development or where
for any other reason there is the future but not immediate possibility of
an agreement on an International Standard;
-
type 3, when a technical committee has collected data of a different
kind from that which is normally published as an International Standard
(“state of the art”, for example).
Technical Reports of types 1 and 2 are subject to review within three years
of publication, to decide whether they can be transformed into International
Standards. Technical Reports of type 3 do not necessarily have to be
reviewed until the data they provide are considered to be no longer valid or
useful.
ISOTTR 13637, which is a Technical Report of type 2, was prepared by the
American Petroleum Institute (API) (as API Recommended Practice 2SK,
2nd edition) and was adopted by Technical Committee lSO/TC 67,
Materials, equipment and offshore structures for petroleum and natural gas
industries, Subcommittee SC 7, Offshore structures.
0 IS0 1997
All rights reserved. Unless otherwise specified, no part of this publication may be reproduced
or utilized in any form or by any means, electronic or mechanical, including photocopying and
microfilm, without permission in writing from the publisher.
International Organization for Standardization
Case postale 56 l CH-1211 Geneve 20 l Switzerland
Internet central @ iso.ch
x.400 c=ch; a=400net; p=iso; o=isocs; s=central
Printed in Switzerland
ii
@ IS0 ISO/TR 13637: 1997(E)
This document is being issued in the Technical Report (type 2) series of
publications (according to subclause G.3.2.2 of part 1 of the ISO/IEC
Directives, 1995) as a “prospective standard for provisional application” in
the field of offshore structures for the petroleum and natural gas industries
because there is an urgent need for guidance on how standards in this field
should be used to meet an identified need.
This document is not to be regarded as an “International Standard”. It is
proposed for provisional application so that information and experience of
its use in practice may be gathered. Comments on the content of this
document should be sent to the IS0 Central Secretariat.
A review of this Technical Report (type 2) will be carried out not later than
three years after its publication with the options of: extension for another
three years; conversion into an International Standard; or withdrawal.

ISO/TR 13637: 1997(E) @ IS0
Introduction
For the purposes of providing interim guidance on mooring/stationkeeping
design, IS0 TC 67/SC 7 has adopted API RP 2SK in recognition that it
constitutes one of the most complete documents on the subject. API RP
2SK contains design guidelines which are based on experience in the
offshore industry, results of several joint industry projects and many
technical publications.
There are several issues that require further consideration and
harmonization prior to this Technical Report being progressed further as
part of IS0 13819-4. These include:
environmental criteria in terms of return periods for temporary and
permanent moorings;
factors of safety for tensions, anchor load and fatigue;
improving the definition and the methodology of the mooring
analysis;
improving the guidelines for thruster-assisted mooring systems;
providing specific guidance in relation to corrosion protection of
mooring lines;
including IMO DP Guidelines (MSC Circ 645 “Guidance for vessel
with dynamic positioning systems”) and relevant industry
standards.
Technical Report ISO/TR 13637 reproduces the content of API
Recommended Practice 2SK, 2nd edition, 1996. ISO, in endorsing this API
document, recognizes that in certain respects the latter does not comply
with all current IS0 rules on the presentation and content of a Technical
Report. Therefore, the relevant technical body, within lSO/TC 67, will
review ISO/TR 13637:1997 and reissue it, when practicable, in a form
complying with these rules.
This Technical Report is not intended to obviate the need for sound
engineering judgement as to when and where this Technical Report should
be utilized and users of this document should be aware that additional or
differing requirements may be needed to meet the needs for the particular
service intended.
Standards referenced herein may be replaced by other international or
national standards that can be shown to meet or exceed the requirements
of the referenced standards.
Appendices A, B, C and D to this document should not be considered as
requirements. They are included only as guidelines or information.
iv
TECHNICAL REPORT o IS0 ISO/rR 13637: 1997(E)
Petroleum and natural gas industries - Mooring of mobile
Design and analysis
offshore drilling units (MODUS) -
1 Scope
This Technical Report presents a rational method for analysing, designing or evaluating mooring systems used with
offshore floating units for the petroleum and natural gas industries.
2 Requirements
Requirements are specified in:
“API Recommended Practice 2SK, 2nd edition, December 1996 - Recommended Practice for Design and
Analysis of Stationkeeping Systems for Floating Structures”
adopted as ISOTTR 13637.
For the purposes of international standardization, however, modifications shall apply to publication API RP 2SK as
outlined below.
a) Information given in the SPECIAL NOTES and FOREWORD is relevant to the API publication only.
b) Throughout publication API RP 2SK, the conversion of English units shall be made in accordance with IS0 31.
The content shall be replaced by the following.
LENGTH 1 inch (in) = 254 mm (exactly)
1 foot (ft) = 304,8 mm
PRESSURE 1 pound-force per square inch (Ibf/inz) or psi = 6 894,757 Pa
NOTE 1 bar = 105 Pa
STRENGTH OR STRESS 1 pound-force per square inch (Ibf/inz) = 6 894,757 Pa
IMPACT ENERGY 1 foot-pound force (ft. Ibf) = 1,355 818 J
TORQUE 1 foot-pound force (ftlbf) = 1,355 818 N-m
TEMPERATURE The following formula was used to convert degrees Fahrenheit (OF) to degrees
Celsius (“C):
“C = 519 (“F - 32)
VOLUME 1 cubic foot = 0,028 316 8 ms or 28,316 8 dms
MASS = 0,453 592 37 kg (exactly)
1 pound (lb)
FORCE 1 pound-force (Ibf) =4,448222 N

ISO/TR 13637: 1997(E)
@ IS0
(Blank page)
lSO/rR 13637: 1997(E)
Recommended Practice for Design and
Analysis of Stationkeeping Systems for
Floating Structures
Exploration and Production Department
API RECOMMENDED PRACTICE 2SK
SECOND EDITION, DECEMBER 1996
EFFECTIVE DATE: MARCH 1, 1997
American
Petroleum
Institute
ISOU-R 13637:1997(E)
SPECIAL NOTES
API publications necessarily address problems of a general nature. With respect to
particular circumstances, local, state, and federal laws and regulations should be re-
viewed.
API is not undertaking to meet the duties of employers, manufacturers, or suppliers
to warn and properly train and equip their employees, and others exposed, concerning
health and safety risks and precautions, nor undertaking their obligations under local,
state, or federal laws.
Information concerning safety and health risks and proper precautions with respect
to particular materials and conditions should be obtained from the employer, the manu-
facturer or supplier of that material, or the material safety data sheet.
Nothing contained in any API publication is to be construed as granting any right, by
implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or
product covered by letters patent. Neither should anything 0 contained in the publication
be construed as insuring anyone against liability for infringement of letters patent.
Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least
every five years. Sometimes a one-time extension of up to two years will be added to this
review cycle. This publication will no longer be in effect five years after its publication
date as an operative API standard or, where an extension has been granted, upon repub-
lication. Status of the publication can be ascertained from the API Authoring Department
[telephone (202) 682~80001. A catalog of API publications and materials is published an-
nually and updated quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005.
This document was produced under API standardization procedures that ensure ap-
propriate notification and participation in the developmental process and is designated as
an API standard. Questions concerning the interpretation of the content of this standard
or comments and questions concerning the procedures under which this standard was de-
veloped should be directed in writing to the director of the Authoring Department (shown
on the title page of this document), American Petroleum Institute, 1220 L Street, N.W.,
Washington, D.C. 20005. Requests for permission to reproduce or translate all or any part
of the material published herein should also be addressed to the director.
API standards are published to facilitate the broad availability of proven, sound en-
gineering and operating practices. These standards are not intended to obviate the need
for applying sound engineering judgment regarding when and where these standards
should be utilized. The formulation and publication of API standards is not intended in
any way to inhibit anyone from using any other practices.
Any manufacturer marking equipment or materials in conformance with the marking
requirements of an API standard is solely responsible for complying with all the appli-
cable requirements of that standard. API does not represent, warrant, or guarantee that
such products do in fact conform to the applicable API standard.
All rights reserved. No part of this work may be reproduced, stored in a retrieval system,
or transmitted by any means, electronic, mechanical, photocopying, recording, or other-
wise, without prior written permission from the publisher: Contact the Publisher;
API Publishing Services, 1220 L Street, N. W, Washington, D. C. 20005.
Copyright 0 I996 American Petroleum Institute
ISOKR 13637: 1997(E)
The bar notations identify parts of this recommended practice that have been changed
from the previous API edition. Note that all sections, paragraphs, figures, and tables have
been renumbered.
This recommended practice is under the jurisdiction of the API Subcommittee on Off-
shore Structures.
API publications may be used by anyone desiring to do so. Every effort has been made
by the Institute to assure the accuracy and reliability of the data contained in them; however,
the Institute makes no representation, warranty, or guarantee in connection with this pub-
lication and hereby expressly disclaims any liability or responsibility for loss or damage re-
sulting from its use or for the violation of any federal, state, or municipal regulation with
which this publication may conflict.
Suggested revisions are invited and should be submitted to the director of the Explo-
ration and Production Department, American Petroleum Institute, 1220 L Street, N.W.,
Washington, D.C. 20005.
This standard shall become effective on the date printed on the cover but may be used
voluntarily from the date of distribution.

ISO/TR 13637: 1997(E)
(Blank page)
ISOTTR 13637: 1997(E)
Pap2
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SCOPE
.................................................
BASIC CONSIDERATIONS
Introduction to Stationkeeping Systems .
2.1
.................
2.2 Differences Between Permanent and Mobile Mooring Systems
.................................................
2.3 Design Considerations
MOORINGCOMPONENTS .
3.1 MooringLine .
3.2 Winching Equipment
..................................................
3.3 Anchoring System
.....................................................
2 1
ENVIRONMENTAL CRITERIA .
Environmental Condition
4.1 .
Environmental Data
4.2 .
4.3 Wind .
4.4 Waves .
Current .
4.5
4.6 Water Depth and Tide
..................................................
4.7 Soil Conditions
.......................................................
4.8 Atmospheric Icing
.....................................................
4.9 Marine Growth
.......................................................
ENVIRONMENTAL FORCES AND VESSEL MOTIONS .
5.1 Basic Considerations .
........ 25
5.2 Guidelines for the Evaluation of Environmental Forces and Vessel Motions
5.3 Simplified Methods .
DESIGNCRITERIA .
6.1 Basic Considerations .
6.2 Offset .
6.3 LineTension .
6.4 Statistics of Peak Values .
6.5 LineLength .
6.6 Holding Power of Anchoring Systems .
6.7 Thruster Assisted Mooring .
6.8 FatigueLife. .
7 MOORING ANALYSIS. .
7.1 Basic Considerations .
....................................... 37
7.2 Quasi-Static and Dynamic Analysis
7.3 Transient Analysis .
Analysis for Thruster Assisted Mooring .
7.4
Fatigue Analysis .
7.5
8 MODELTESTING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
................................
9 SINGLE ANCHOR LEG MOORING SYSTEMS
...................................................
9.1 Basic Considerations
..............................................
9.2 Special Design Conditions
.............................................
9.3 Extreme Response Analysis
V
.................................... 45
9.4 Design Criteria for Extreme Responses
...................................................... 45
9.5 Fatigue Analysis
........................................... 45
9.6 Special Design Considerations
.........................................
10 DYNAMIC POSITIONING SYSTEM 46
................................................... 46
10.1 Basic Considerations
....................................... 48
10.2 Basic Concept and Major Elements
................................................... 59
10.3 Design and Analysis
.................................................. 65
10.4 DP System Operation
11 DESIGNEXAMPLES .
..................................... 68
11.1 Extreme Response Analysis Example
.............................................. 74
11.2 Fatigue Analysis Example
Figures
1-SpreadMooring .
.............................................. 3
2-TLP Lateral Mooring System
................................ 4
3-Typical External Turret Mooring Arrangement
................................. 5
4-Typical Internal Turret Mooring Arrangement
.........................................
5-Variations on Turret/Riser Systems 6
6-Catenary Anchor Leg Mooring (CALM) with Hawsers . 7
................. 9
7-Catenary Anchor Leg Mooring (CALM) System with Fixed Yoke
.................. 10
8-Catenary Anchor Leg Mooring (CALM) System with Soft Yoke
9-Single Anchor Leg Mooring (SALM) with Tubular Riser and Yoke . 10
IO-Single Anchor Leg Mooring (SALM) with Chain Riser and Hawser . 11
1 l-Dynamic Positioning . 12
12-Different Wire Line Constructions . 14
13-Submersible Buoy Configurations . 16
14-Winching System Using Linear Winch and Bending Shoe . 18
15-Installation of Caisson Foundation (Suction Anchor) . 19
16-U-S. Navy Propellant Embedment Anchor . 20
17-Wave Height/Wave Period Relationship . 24
18-Drag Embedment Anchors . 29
19-Anchor System Holding Capacity in Soft Clay . 30
20-Anchor System Holding Capacity in Sand . 31
21-Fatigue Design Curves . 34
22-System Dynamic Analysis . 41
23Major Elements of a Dynamic Positioning System .
24-Dynamic Positioning Loop . 47
25-Three Axis Controller and Thruster Allocation Logic .
26-Position Sensing Systems . 49
27-Principle of Operation of the SBS . 50
28-Acoustic Wave Phase Relationship . 5 1
%--System Implementation of a Long Baseline System .
30-Taut WireSystem . 53
31-Adaptive Riser Angle Reference System (ARARS) . 53
32-Communication Satellites for STARFIX System . 54
................................................ 55
33-Gyrocompass Schematic
......................... 55
34-Pendulous Mass Vertical Reference Sensor Schematic
............................................ 56
35-Open Propeller-Type Thruster
................................................ 56
36-Typical Ducted Propeller
.................................. 57
37-Typical Retractable Thruster Configuration
........................................... 57
38-Typical Thruster Configuration
VI
........................................
39----J&& Elements of a Power System
........ 61
4@--Generation of Reliability Measures at the Various Levels of the DP System
............................
4 l-Dynamic Positioning Holding Capability Rosettes
..................................................
42---Mooring Configuration
.................................................
43----Spectral Decomposition
................................................
44-Selection of Input Motion
..............................
45-Mooring System and Environmental Directions
..... 80
A-1-Semisubmersible Current Drag Coefficient for Members Having Flat Surfaces
...............................................
A-2-Wave Force Components
........................ 84
A-3-Wave Drift Force and Motion for Drillships Bow Seas
........................ 85
A-4-Wave Drift Force and Motion for Drillships Bow Seas
........................ 86
A-5-Wave Drift Force and Motion for Drillships Bow Seas
............. 87
A-6-Wave Drift Force and Motion for Drillships Quartering Seas, Surge
............. 88
A-7-Wave Drift Force and Motion for Drillships Quartering Seas, Surge
............. 89
A-8-Wave Drift Force and Motion for Drillships Quartering Seas, Surge
.............. 90
A-9-Wave Drift Force and Motion for Drillships Quartering Seas, Sway
............. 9 1
A- lo-Wave Drift Force and Motion for Drillships Quartering Seas, Sway
............. 92
A-l l-Wave Drift Force and Motion for Drillships Quartering Seas, Sway
...................... 93
A-12-Wave Drift Force and Motion for Drillships Beam Seas
...................... 94
A-13-Wave Drift Force and Motion for Drillships Beam Seas
...................... 95
A-14-Wave Drift Force and Motion for Drillships Beam Seas
............... 96
A-15-Wave Drift Force and Motion for Semisubmersibles-Bow Seas
.......... 97
A-16-Wave Drift Force and Motion for Semisubmersibles-Quartering Seas
.............. 98
A-17-Wave Drift Force and Motion for Semisubmersibles-Beam Seas
...............................................
B-l-Effect of Cyclic Loading
..............................................
B-2-Effects of Anchor Soaking
...................... 102
B-3-Percent Holding Capacity Versus Drag Distance in Mud
.......................................
C- 1 -Propeller Thrust-Open Propellers
.................................
C-2-Propeller Thrust-Propellers with Nozzles
............................
.............. 108
,.
C-3-Side Force-Tunnel Thrusters
Tables
............................................
I-Fairlead Motion Complex RAO
.......................................................
2-Tension Spectrum
3-Environmental Condition, Mean Loads and Low-Frequency Motions for the
......................................................
Analyzed Direction
4-WireRopeDamage .
.........................................................
5-ChainDamage
.......................
6-Annual Fatigue Damage as a Function of the Environment
..........................................
A- 1 -Wind Force Shape Coefficients
........................
A-2-Wind Force Height Coefficients (For l-Minute Wind)
.............................................
A-3-Wind Velocity Time Factor
......... 101
B- l-Estimated Maximum Fluke Tip Penetration of Some Drag Anchor Types
.....................................
C-l-Correction Factor for Inflow Velocity
.......................................
C-2-Thrust Losses in Reverse Condition
APPENDIX A-SIMPLIFIED METHODS FOR THE EVALUATION OF
. . . . . . . . . . . . . . . 79
ENVIRONMENTAL FORCES AND VESSEL MOTIONS
APPENDIX B-COMMENTARY ON DRAG ANCHOR PERFORMANCE EVALUATION . .
APPENDIX C-DETERMINATION OF AVAILABLE THRUST . . . . . . . . . . . . . . . . . . . . . . . . 105
APPENDIX D-REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111
VII
ISO/rR 13637: 1997(E)
Recommended Practice for Design and Analysis of Stationkeeping Systems
for Floatina Structures
mersible based floating production system. Since it fixes the
1 Scope
position of the vessel, drilling and completion operations can
The purpose of this document is to present a rational
be carried out on subsea wells located immediately below the
method for analyzing, designing or evaluating mooring sys-
vessel. The same is true for workover operations. On the
tems used with floating units. This method provides a uni-
other hand, a spread mooring system has a fairly large moor-
form analysis tool which, when combined with an
ing spread (on the order of several thousand feet). Anchors
understanding of the environment at a particular location, the
and suspended mooring lines are present within this spread.
characteristics of the unit being moored, and other factors,
These must be considered in the installation or maintenance
can be used to determine the adequacy and safety of the
of pipelines, risers, or any other subsea equipment.
mooring system. Some design guidelines for dynamic posi-
The combination of a spread mooring with vertical moor-
tioning systems are also included.
ing tendons to restrain a tension leg platform (TLP) on loca-
The technology of mooring floating units is growing
tion, as shown in Figure 2 enhances both the operability and
rapidly. In those areas where the committee felt that adequate
reliability of the basic TLP concept. The spread mooring al-
data were available, specific and detailed recommendations
lows for adjustment of the surface vessel in a controlled man-
are given. In other areas general statements are used to indi-
ner and provides an independent parallel load path to react
cate that consideration should be given to those particular
against the lateral environmental forces. With this concept it
points. Designers are encouraged to utilize all research ad-
is possible to horizontally position drilling tools and produc-
vances available to them. As offshore knowledge continues to
tion equipment packages to be landed and attached to
grow, this recommended practice will be revised. It is hoped
seafloor structures. Otherwise, these equipment packages
that the general statements contained herein will gradually be
would have to be positioned by other means such as guide-
replaced by detailed recommendations.
lines, thrusters, or skidding the derrick on the surface vessel.
The configuration and design of this spread mooring will be
2 Basic Considerations
very similar to a spread mooring system used to moor
2.1 INTRODUCTION TO STATIONKEEPING semisubmersible based floating production systems.
SYSTEMS
2.1.2 Single Point Mooring
The stationkeeping system for a floating structure can be
either a single point mooring or a spread mooring. Single Single point moorings are used primarily for tankers. They
point moorings tend to be used more frequently for ship allow the vessel to weather vane. This is necessary to mini-
shaped vessels, while spread moorings are used mostly for mize environmental loads on the tanker by heading into the
semisubmersibles. A third type of stationkeeping system is prevailing weather. There is wide variety in the design of sin-
dynamic positioning (DP). Dynamic positioning can be used gle point moorings, but they all perform essentially the same
as the sole source of stationkeeping or used to assist a cate- function. Single point moorings interface with the production
nary mooring. Dynamic positioning can be used with either riser and the vessel. An introduction to typical single point
tanker or semisubmersible based systems. mooring systems is as follows:
a. Turret mooring. A turret mooring system is defined as any
2.1 .l Spread Mooring
mooring system where a number of catenary mooring legs
Figure 1 is an illustration of a catenary spread moored are attached to a turret that is essentially part of the vessel to
semisubmersible. This is a conventional mooring technique be moored. The turret includes bearings to allow the vessel to
used in floating drilling operations. For floating production rotate around the anchor legs.
applications, spread moorings are used primarily with The turret can be mounted externally from the vessel bow
semisubmersibles. Since the environmental force on a or stern with appropriate reinforcements (see Figure 3-Ex-
semisubmersible is relatively insensitive to direction, a ternal Turret Mooring System) or internally within the vessel
spread mooring system can be designed to hold the vessel on (see Figure 4-Internal Turret Mooring). The chain table can
location regardless of the direction of the environment. How- be above or below the waterline. The turret also could be in-
ever, this system can also be applied to ship-shaded vessels
tegrated into a vertical riser system that is attached to the bow
which are more sensitive to environmental directions. The
or stern of the vessel (or internally) through some kind of
mooring can be chain, wire rope, fiber rope, or a combination
mechanism that allows articulation (gimballed table, “I-J”
of the three. Either conventional drag anchors or anchor piles
joint or chain connections). The base of the riser is often
can be used to terminate the mooring lines.
weighted through additional weight within the riser or sus-
A spread mooring offers some advantages to the semisub-
pended beneath the riser (counterweight). These items affect
ISO/TR 13637: 1997(E)
API RECOMMENDED PRACTICE 2SK
?
L
. .
4 :
a ;
, . .
-
z
8-
I
iit
.$
LL
P n
W
n
DRILLING AND
PRODUCTION
EQUIPMENT
/ BUOYANT
SUPERSTRUCTURE
E
ERSIBLE
‘S
WIRE ROPE AND CHAIN
LATERAL MOORING
.
LINE
TENDONS
PACKAGE OF DRILLING
‘TOOLS BEING RUN
TO WELL
PRODUCTION RISER -
FROM COMPLETED
WELL
SEAFLOOR FOUNDATION
/
Figure Z-TLP Lateral Mooring System

ISO/TR 13637: 1997(E)
API RECOMMENDED PRACTICE 2SK
UPPER CONNECTION STRUCTURE 7
VW-- --.
-f
FLOATING STORAGE UNIT
ES.U.)
VERTICAL
TURRET SHAFT
f
LOWER CONNECTION STRUCTURE \
\ t CHAINTABLE
MOORING CHAIN (TYP.)
Figure 3-Typical External Turret Mooring Arrangement
,IN-LINE SWIVEL
UPPER CONNECTION STRUCTURE
.
FLOATING STORAGE UNIT
.
(F.S.U.)
VERTICAL
TURRET SHAFT
TURRET WELL WALL%
LOWER CONNECTION STRUCTURE
MOORING CHAIN (TYP.)
Figure 4-Typical Internal Turret Mooring Arrangement

SWIVEL JOINT
l7lib
JOINT
SWIVEL JOINT\
hB!ik
LER BEAR ING
ROLLER BEARING
-.- 1
Y- U-JOINT
ROLLER BEARING 4
MECHANICAL
U - JOINT.--=&v/
CONNECTOR
‘8
--f T-r
: I
CYLINDRICAL
SHAFT
COUNTERWEIGHT
OUNTERWEIGHT
C
CHAINTABLE
- CHAIN
-
/
\
\
BUOYANT
CHAIN RISER
TURRET RISER SYSTEM
COUNTERWEIGHT IGHT
COUNTERWE
SYSTEM
SYSTEM
Figure 5-Variations on Turret/Riser Systems

lSo/TR 13637:1997(E)
RECOMMENDED PRACTICE FOR DESIGN AND ANALYSIS OF STATIONKEEP~NG SYSTEMS FOR FLOATING STRUCTURES
.
f
I
l
.=
.’
l
.
.*
:
.
.’
:
.**
.
:
.;
l
z
MOORING LINE
Figure 6-Catenary Anchor Leg Mooring (CALM) with Hawsers
API RECOMMENDED PRACTICE 2SK
2.2 DIFFERENCES BETWEEN PERMANENT AND
the performance of the mooring system. The configuration of
MOBILE MOORING SYSTEMS
the riser could include steel tubular, chain or wire rope com-
ponents and can vary considerably in diameter and length.
Permanent moorings are normally used for production op-
The position of the chain table relative to the riser also can
erations with longer design lives. The mooring for a floating
vary according to the design. Figure 5 shows some variations
production system (FPS), for example, is a permanent moor-
in the turret design offered by industry.
ing since FPSs typically have design lives of over 10 years.
b. CALM (catenary anchor leg mooring). The CALM sys-
Mobile moorings often stay on one location for a short peri-
tem consists of a large buoy that supports a number of cate-
od. Examples of mobile moorings include those for mobile
nary chain legs anchored to the sea floor (Figure 6). Riser
offshore drilling units (MODUS), and for tenders moored
systems or flow lines that emerge from the sea floor are at-
next to another platforms such as floatels, drilling tender, and
tached to the underside of the CALM buoy. Some of the sys-
service vessels. The division between mobile and permanent
tems use a hawser, typically a synthetic rope, between the
moorings may not be clear for operations with design lives of
tanker and the buoy. Since the response of the CALM buoy is
a few years. In this case, the user should make a judgment
totally different than that of the tanker under the influence of
based on the risk of exposure to severe environments and the
waves, this system is limited in its ability to withstand envi-
consequence of a mooring failure. Differences between per-
ronmental conditions. When sea states attain a certain magni-
manent and mobile moorings are significant, as discussed be-
tude it is necessary to cast the tanker off.
low. The discussion can be used as a guideline to determine
In order to overcome this limitation, rigid structural yokes
the category (permanent or mobile) to which the floating
with articulations are used in some newer designs to tie the
structure belongs.
ship to the top of the buoy. An example is shown in Figure 7.
This rigid articulation virtually eliminates horizontal motions
2.2.1 Type of Mooring
between the buoy and the tanker. A more recent develop-
A mobile vessel is normally equipped with a spread moor-
ment, shown in Figure 8, is a buoyant yoke with a soft moor-
ing, internal turret mooring, or dynamic positioning system.
ing connection using chains attached to the yoke.
However, a permanent vessel has more choices of mooring
c. SALM (single anchor leg mooring). This system employs
design because mobility is normally not required.
a vertical riser system that has a large amount of buoyancy
near the surface, and sometimes on the surface, that is held by
2.2.2 Environmental Criteria
a pretensioned riser. The system typically employs a tubular,
articulated riser with a fixed yoke (Figure 9). It is possible
The design environments for mobile moorings are lower
also to use a chain riser with soft mooring connections (Fig-
than those for permanent moorings. The lower design envi-
ure 10). The vertical buoyancy force acting on the top of the
ronment for mobile moorings is based on the consideration
riser functions as an inverted pendulum. When the system is
that the consequence of a mooring failure would generally be
displaced to the side, the pendular action tends to restore the
less severe. This can be illustrated by comparing a MODU
riser to the vertical position.
with an FPS. In many instances, a MODU can at least discon-
The tanker can be secured to the top of this SALM buoy
nect and may even lay down its drilling riser. In the case of
with either a flexible hawser or a rigid yoke as discussed in
tropical storms, it may be possible to move the vessel before
the CALM description. The base of the riser is usually at-
the arrival of a storm. By contrast, an FPS is unlikely to be re-
tached through a U-joint to a piled or deadweight concrete or
movable from location, and may not even have quickly-
steel structure on the sea floor. In deep water, the riser system
retrievable risers.
usually has mid-span articulation.
2.2.3 Method of Analysis
2.1.3 Dynamic Positioning
A quasi-static analysis method is normally used for evalu-
ating the performance of a mobile mooring system, and the
Dynamic positioning (Figure 11) can be used as the sole
effects of line dynamics are accommodated through the use
source of stationkeeping or used to assist a catenary mooring
of a relatively conservative safety factor. A more rigorous dy-
system. Dynamic positioning consists of a position reference
namic analysis is required for the final design of a permanent
system, usually acoustic, coupled with computer controlled
mooring system, and the factor of safety is relaxed to reflect
thrusters around the vessel. Dynamic positioning can be used
that some uncertainty in line tension prediction is removed.
in conjunction with a mooring which is called DP assisted Dynamic analysis should also be performed for mobile moor-
mooring (or thruster assisted mooring if thrusters are manu- ings if the consequence of a mooring failure is severe.
Also, a fatigue analysis is not required for mobile mooring
ally controlled). Dynamic positioning is particularly well
systems. Because of abuse from frequent deployment and
suited for a vessel designed to come onto and leave location
retrieval, many mooring components of a mobile mooring
frequently, such as an extended well test system.
ISOmR 13637:1997(E)
RECOMMENDED PRACTICE FOR DESIGN AND ANALYSIS OF STATIONKEEPING SYSTEMS FOR FLOATING STRUCTURES
.
l
. \
.
.
i
l
.
.
/- \
,
Figure 7-Catenary Anchor Leg Mooring (CALM) System with Fixed Yoke
10 API RECOMMENDED PRACTICE 2SK
/CHAIN
HEAVY WEIGHT
MOORING LINE-
/
Figure 8-Catenary Anchor Leg Mooring (CALM) System with Soft Yoke
-.
-
-
-
L
A’* 0-
BUOY SEtiN
I I
RISER SECT
Figure 9-Single Anchor Leg Mooring (SALM) with Tubular Riser and Yoke
ISO/rR 13637:1997(E)
RECOMMENDED PRACTICE FOR DESIGN AND ANALYSIS OF STATIONKEEPING SYSTEMS FOR FLOATING STRUCTURES
CHAIN RISER
.
.
.
- .
.
. .
-. -
.
Figure IO-Single Anchor Leg Mooring (SALM) with Chain Riser and Hawser

ISOnR 13637: 1997(E)
API RECOMMENDED PRACTICE 2SK
system are replaced before they reach their fatigue limits.
However, for permanent installations such as an FPS, fatigue
is an important design factor, and a fatigue analysis should be
performed.
2.2.4 Mooring Hardware
Mobile moorings use the mooring hardware that can be
rapidly deployed and retrieved. This limitation does not apply
to permanent moorings. Many mooring components such as
anchor piles, linear winches, buoys, and chain jacks that may
not be suitable for mobile moorings can be used in a perma-
nent mooring. Also permanent moorings often require heav-
ier mooring hardware because of the more stringent design
requirements.
2.2.5 Installation
The deployment of a mobile mooring is normally carried
out with the assistance of work boats. This operation is sim-
ple and usually takes no more than a few days. The deploy-
ment of an FPS mooring often requires the assistance of
much heavier vessels such as a derrick barge or a purposely
built work boat. A portion of the mooring is usually preset.
Sometimes special design features are incorporated in the
Figure 11 -Dynamic Positioning
mooring design to facilitate deployment.
2.2.6 Inspection and Maintenance
designed to accommodate each other, and coordination of
these two design efforts is essential.
A mobile mooring can often be visually inspected during
Design guidelines for riser systems can be found in API
retrieval or deployment. Retrieving a permanent mooring for
Recommended Practice 17A [S], API Recommended Practice
inspection can be very expensive. To inspect a permanent
17B, [6], and API Recommended Practice 16Q [7].
mooring, divers or ROVs are often used. Also, replacing
faulty mooring components is easier for mobile moorings
2.3.3 Subsea Equipment Considerations
than for permanent moorings.
Subsea equipment such as templates, riser bases, satellite
wells, and flowlines should be located clear of any potential
2.3 DESIGN CONSIDERATIONS
mooring line interference. Any contact between mooring
lines and subsea equipment during installation, operation or
2.3.1 Primary Design Considerations
maintenance presents a high potential of damage to both the
The primary design considerations associated with a moor-
equipment and the mooring lines. If interference, or the po-
ing system are design criteria, design loads, design life,
tential for interference appears unavoidable, it may be possi-
operation and maintenance considerations. These considera-
ble to alter the layout and design of the mooring system
tions are addressed in detail in the following sections. In ad-
through the use of an asymmetric arrangement of mooring
dition, a designer must also pay attention to the riser and
lines, or the use of clump weights or spring buoys. Coordina-
subsea equipment considerations.
tion of the mooring system design with the subsea equipment
layout is essential.
2.3.2 Riser Considerations
Guidelines for the design of subsea equipment are given in
Risers transfer fluids between the seabed and the produc-
API Recommended Practice 17A.
tion or drilling vessel, and constitute one of the primary
design constraints of the mooring system. The riser system
3 Mooring Components
often places limitations on the allowable vessel offset. In the
3.1 MOORING LINE
event of excessive vessel offsets, mooring line adjustments
such as slackening the leeward lines are sometimes per-
3.1 .l Classification
formed to avoid damage to the riser. An equally important
Mooring lines for moored vessels may be made up of
consideration is interference between mooring lines and ris-
chain, wire rope, synthetic rope, or a combination of them.
ers, during both operational and extreme weather conditions.
There are many possible combinations of line type, size, and
The mooring system and riser system must therefore be
ISO/TF? 13637:1997(E)
RECOMMENDED PRACTICE FOR DESIGN AND hJALySlS OF STATIONKEEPING SYSTEMS FOR FLOATING STRUCTURES
location, and size of clump weights or buoys that can be used been sold in large quantities to drilling contractors over the
to achieve given mooring performance requirements. The f’d- years and has generally performed well. Grade 3 chain has a
catalogue break strength of approximately 93 percent of the
lowing are typical systems used by the industry:
equivalent ORQ chain, and K4 chain has a catalogue break
strength of approximately 130 percent of the equivalent ORQ
3.1 .l .l All-Wire Rope System.
chain. Grade 2 chain is not recommended for major mooring
Because wire rope is much lighter than chain, wire rope
operations.
provides a greater restoring force for a given pretension. This
A grade of chain somewhere between ORQ and K4, for
becomes increasingly important as water depth increases.
example “ORQ + 20 percent” (breaking strength 20 percent
However, to prevent anchor uplift with an all-wire system,
higher than ORQ), is preferred by some designers since it is
much longer line length is required. A disadvantage of an all-
easier to manufacture than K4 chain. In any case it is recom-
wire rope mooring system is wear due to long term abrasion
mended that considerable care is taken in establishing correct
where it contacts the seabed. For these reasons, all-wire rope
chemical composition of the bar stock, manufacturing tech-
mooring systems are seldom used for permanent moorings.
niques that in
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