Recommended Practice
for
Subsea Pipelines
January 2023
Recommended Practice for Subsea Pipelines - January 2023
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referred to in this clause as ‘Lloyd's Register’. Lloyd's Register assumes no responsibility and shall not be liable to any person for any loss,
damage or expense caused by reliance on the information or advice in this document or howsoever provided, unless that person has signed a
contract with the relevant Lloyd's Register entity for the provision of this information or advice and in that case any responsibility or liability is
exclusively on the terms and conditions set out in that contract.
Recommended Practice for Subsea Pipelines – January 2023
Contents
Contents
CHAPTER 1:
Recommended Practice for Subsea Pipelines ......................................................................... 1
Section 1:
Introduction ................................................................................................................................. 1
Section 2:
General design approach ........................................................................................................... 5
Section 3:
Offshore installation safety ........................................................................................................ 7
Section 4:
Pipeline analysis ....................................................................................................................... 11
Section 5:
Pipe-in-pipe Systems................................................................................................................ 26
Section 6:
Bundles ...................................................................................................................................... 32
Section 7:
Subsea piping modules ............................................................................................................ 33
Section 8:
Out-of-straightness (OOS) assessment .................................................................................. 34
Section 9:
Change of use ........................................................................................................................... 45
Recommended Practice for Subsea Pipelines – January 2023
Chapter 1 – Section 1
CHAPTER 1:
Recommended Practice for Subsea Pipelines
Section 1: Introduction
Section 2: General design approach
Section 3: Offshore installation safety
Section 4: Pipeline analysis
Section 5: Pipe-in-pipe Systems
Section 6: Bundles
Section 7: Subsea piping modules
Section 8: Out-of-straightness (OOS) assessment
Section 9: Change od use
Section 1:Introduction
1.1
General
1.1.1
Foreword
1.1.1.1 Subsea pipeline systems are a critical component of offshore oil and gas developments and are
generally recognised as the safest and most economical means of transporting fluids such as oil and gas
between subsea wells and offshore installations and for export to an end user. As the energy industry transitions
towards cleaner sources of energy, subsea pipelines are set to continue to serve as a safe and reliable conduit to
transport fluids such as hydrogen and CO2.
1.1.1.2 The offshore industry has developed several well-established and mature standards which can be
selected and applied for the design of subsea pipelines. In general, the available National and International
Codes and Standards include primarily normative requirements which must be satisfied to comply with the
standard. However, most of the available standards do not include detailed guidance on how to perform specific
assessments and may also permit the user to adopt alternative approaches to those stated within the standard.
1.1.1.3 Within the pipelines industry, best practices have been developed to address the design of subsea
pipeline systems where the standards are not definitive. This Recommended Practice (RP) has been developed
based on Lloyd's Register’s (hereinafter referred to as LR) experience of these industry best practices.
1.1.2
Objectives
1.1.2.1 The objective of this RP is to provide supplementary guidance in addition to the industry codes and
standards listed in Section 1.2 References of this document. The guidance contained within this document is
intended to represent what is considered by LR to be best practice in the pipelines industry.
1.1.2.2 It is not intended that this RP is used in isolation as design guidance. An appropriate primary design
Code should be selected and applied consistently throughout the pipeline design, and this RP may be used as a
reference in cases where the primary design Code is silent or permits alternative approaches. This RP has not
been written as a supplement to any specific design Code or standard and should therefore be read as
supplementary guidance only.
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Chapter 1 – Section 1
1.1.2.3 Where information contained within this RP conflicts with the requirements of the Codes and Standards
listed in Section 2.1.2 Application of standards, the primary design Code shall take precedence.
1.1.3
Scope
1.1.3.1 This RP is currently applicable only to subsea steel pipeline systems transporting petroleum and natural
gas products, including associated steel riser(s) on fixed or floating offshore platforms and any landfall sections
up to the location of the onshore/offshore pipeline code break.
1.1.3.2 The guidance also covers pipeline components, namely bends, flanges, fittings, bulkheads and anchor
flanges. Non-metallic, bonded and unbonded flexible pipelines and risers are outside of the scope of this
document.
1.1.3.3 The analysis methods presented within this document may be applied for the assessment of pipelines
transporting fluids such as hydrogen or carbon dioxide; however, careful consideration should be given to the
effect of the fluids on the materials and any special safety requirements and environmental consequences.
1.1.4
Audience
1.1.4.1 For organisations that will develop equipment or systems and require a means of third-party certification
where no statutory requirements exist, the RP may be used for that purpose, and:
•
•
•
1.1.5
Regulators may use and choose to adopt the RP for their purposes, be it setting it as a standard or
adopting it in law.
The document is intended to be used for project certification of installations, which also includes
vendor equipment supplied to the project.
Where RPs are applied to discreet systems they may be used in an equipment certification context.
Governance
1.1.5.1 Lloyd’s Register Group Limited is managed by a Board of Directors (hereinafter referred to as 'the
Board'). The Board has appointed a Lloyd's Register Offshore Technical Committee and determined its powers,
functions and duties. This RP has been reviewed by the Lloyd’s Register Offshore Technical Committee for
suitability in its application to the offshore environment.
1.1.6
Verification
1.1.6.1 LR will provide independent verification statements and reports describing compliance with the
provisions of the RP. These may be expected to be used by duty holders and certifying authorities in the
certification process for an installation.
1.1.7
Ethics
1.1.7.1 No LR Group employee is permitted under any circumstances to accept, directly or indirectly, from any
person, firm or company with whom the work of the employee brings the employee into contact, any present,
bonus, entertainment or honorarium of any sort whatsoever which is of more than nominal value, or which might
be construed to exceed customary courtesy extended in accordance with accepted ethical business standards.
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Recommended Practice for Subsea Pipelines – January 2023
Chapter 1 – Section 1
1.1.8
Non-payment of fees
1.1.8.1 LR has the power to withhold any certificate or report, in the event of non-payment of any fee to any
member of the LR Group.
1.1.9
Limits of liability
1.1.9.1 When providing services, LR does not assess compliance with any standard other than the applicable
codes and standards agreed in writing.
1.1.9.2 In providing services, information or advice, LR does not warrant the accuracy of any information or
advice supplied. Except as set out herein, LR will not be liable for any loss, damage or expense sustained by any
person and caused by any act, omission, error, negligence or strict liability of LR or caused by any inaccuracy in
any information or advice given in any way by or on behalf of LR even if held to amount to a breach of warranty.
Nevertheless, if the Client uses LR services or relies on any information or advice given by or on behalf of LR and
as a result suffers loss, damage or expense that is proved to have been caused by any negligent act, omission or
error of LR or any negligent inaccuracy in information or advice given by or on behalf of LR then LR will pay
compensation to the client for its proved loss up to but not exceeding the amount of the fee (if any) charged for
that particular service, information or advice.
1.1.9.3 LR will print on all certificates and reports the following notice: Lloyd’s Register Group Limited, its
affiliates and subsidiaries and their respective officers, employees or agents are, individually and collectively,
referred to in this clause as ‘Lloyd's Register’. Lloyd's Register assumes no responsibility and shall not be liable
to any person for any loss, damage or expense caused by reliance on the information or advice in this document
or howsoever provided, unless that person has signed a contract with the relevant Lloyd's Register entity for the
provision of this information or advice and in that case any responsibility or liability is exclusively on the terms and
conditions set out in that contract.
1.1.9.4 Except in the circumstances of Section 1.1.9 Limits of liability 1.1.9.2, LR will not be liable for any loss of
profit, loss of contract, loss of use or any indirect consequential loss, damage or expense sustained by any
person caused by any act, omission or error, or caused by any inaccuracy in any information or advice given in
any way by or on behalf of LR even if held to amount to a breach of warranty.
1.1.9.5 Any dispute about LR services is subject to the exclusive jurisdiction of the English courts and will be
governed by English law.
1.1.10
Explanatory note
1.1.10.1 The inspection and survey of offshore structures is subject to the local laws and regulatory requirements
as applicable. As such, elements within the RP may need to be modified to achieve local legal and regulatory
compliance.
1.1.11
Use of shall and may
1.1.11.1 The use of the word ‘shall’ requires strict conformance with the requirements set forth within the
document. The use of ‘may’ provides general guidance and options.
1.1.11.2 In the case of the use of may, in the general guidance and options, upon application to LR a submission
may be made for alternatives to the RP guidance so long as they provide an equal or greater level of safety. In
these instances, the solution is likely to be novel and may require qualification under such schemes as LR’s
‘Technology Qualification’ programme.
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Chapter 1 – Section 1
1.2
References
1.2.1
Reference documents
API SPEC 5L
ASME B31.4
ASME B31.8
BS EN 10021
BS EN 10225-1
Specification for Line Pipe
Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids
Gas Transmission and Distribution Systems
General technical delivery conditions for steel products
Welded structural steels for fixed offshore structures – Technical delivery
conditions – Plates
Hot rolled products of structural steels – Technical delivery conditions for nonalloy structural steels
Petroleum and natural gas industries – Steel pipe for pipeline transportation
systems
Pipeline Systems – Part 1: Steel pipelines on land – Code of practice
Pipeline systems – Part 2: Subsea pipelines – Code of practice
Free Spanning Pipelines.
Duplex stainless steel – design against hydrogen induced stress cracking
Submarine pipeline systems
Petroleum and natural gas industries – Pipeline transportation systems
A Guide to the Pipelines Safety Regulations 1996
Design of Submarine Pipelines Against Upheaval Buckling
Reliability-based limit state methods
BS EN 10025-2
BS EN ISO 3183
BS PD 8010-1
BS PD 8010-2
DNV-RP-F105
DNV-RP-F112
DNV-ST-F101
ISO 13623
L82
OTC 6335
ISO 16708
1.3
Abbreviations and definitions
1.3.1
Abbreviations
1.3.1.1 The following abbreviations are applicable to this RP unless otherwise stated:
ASME
ALARP
AWTI
BPVC
CITHP
EAF
EOL
ESDV
FEA
FIV
FLET
FORM/SORM
GRP
HIPPS
HISC
KP
LB
MAOP
NDE
NUI
OHTC
OOS
PCS
PLEM
PLET
4
American Society of Mechanical Engineers
As low as reasonably practicable
Above water tie-in
Boiler and Pressure Vessel Code
Closed-in tubing head pressure
Effective axial force
End-of-life
Emergency shutdown valve
Finite element analysis
Flow induced vibration
Flowline end termination
First/second-order reliability method
Glass reinforced plastic
High integrity pressure protection system
Hydrogen induced stress cracking
Kilometre point
Lower bound
Maximum allowable operating pressure
Non-Destructive Examination
Normally unmanned installation
Overall heat transfer coefficient
Out-of-straightness
Pipeline control system
Pipeline end manifold
Pipeline end termination
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Chapter 1 – Sections 1 & 2
PSS
QRA
RP
SCF
SIF
SIL
SOL
SRA
SSIV
SMYS
UB
UTS
VIV
Pipeline safety system
Quantitative risk assessment
Recommended Practice
Stress concentration factor
Stress intensification factor
Safety integrity level
Start-of-life
Structural reliability assessment
Subsea isolation valve
Specified minimum yield stress
Upper bound
Ultimate tensile strength
Vortex induced vibration
Section 2:General design approach
2.1
General
2.1.1
Compliance hierarchy
2.1.1.1 It is recommended that each pipeline design project establishes a clear precedence/hierarchy of
requirements to ensure clear guidance to the project in the event of any conflict between the applicable
references (laws and Regulations, standards, Recommended Practice, specifications, etc.).
2.1.1.2 The hierarchy of requirements which governs the pipeline design approach is summarised in Figure 2.1
Requirements hierarchy.
Figure 2.1 Requirements hierarchy
2.1.1.3 The applicable regulatory requirements, which govern for the pipeline under consideration, may be goalbased, prescriptive or non-prescriptive with regards to requirements for pipeline design, construction, operation
and decommissioning. Table 2.1 Typical regulatory frameworks outlines the features of typical regulatory
framework types.
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Chapter 1 – Section 2
Table 2.1
Typical regulatory frameworks
Regulatory
Framework Type
Goal-based
Prescriptive/Rulesbased
Not well
defined/developed
Features
Where legislation is goal-based, the Regulations generally do not prescribe the
means to achieve a safe design but set objectives which may be achieved by multiple
approaches. This allows the pipeline Owner/Operator to apply current best practices.
In some cases, guidance may be published by the regulator clarifying acceptable
International Codes and Standards; however, this is generally not included within the
Regulations.
Therefore, a goal-based approach is generally regarded as best practice for the
design of complex offshore installations.
Where legislation is prescriptive, a set of rules or criteria are defined by the regulator
which if complied with will meet the overall objective of the Regulation. Normally, a
pipeline design standard will be referenced within prescriptive Regulations with
additional rules and requirements.
Since prescriptive/rules-based Regulations may reference specific standards and
requirements, in some cases prescriptive Regulations may lag behind industry best
practice/innovation.
Where Regulations may not be well defined/developed, there may be limited guidance
for the design approach to offshore installations or pipelines. In such cases,
Owners/Operators define the overall design safety objectives and means to achieve
these objectives.
It is currently best practice to apply a goal-based approach in the absence of other
guidance.
2.1.1.4 Where the regulatory framework does not specify a primary design standard for the pipeline system, the
project should nominate a suitable primary design standard. Codes and standards which are considered to be
acceptable to LR are listed in Section 2.1.2 Application of standards.
2.1.2
Application of standards
2.1.2.1 Where local Regulations do not specify a primary design Code, the selection of a standard from Table
2.2 Codes and Standards is recommended. The principal design standard should be followed in a consistent
manner to determine the physical extents (battery limits or code break limits) of a given pipeline system to which
that standard should be applied.
2.1.2.2 Where pipelines are designed to standards which primarily include normative requirements (such as
ISO 13623), it is further recommended that reference is also made to compatible industry best practice guidelines
and RPs for guidance on how to meet the normative requirements.
2.1.2.3 Mixing of provisions or requirements from different codes (e.g. line pipe specifications, test pressures,
calculation methodologies and safety factors) is not recommended unless a thorough gap analysis has been
performed to demonstrate that the resultant pipeline design achieves an equivalent level of safety as required by
the principal design standard.
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Chapter 1 – Sections 2 & 3
Table 2.2
Codes and Standards
Document Number
ISO 13623
ASME B31.8
Document Title
Petroleum and natural gas industries – Pipeline
transportation systems
Pipeline systems – Part 2: Subsea pipelines –
Code of practice
Pipeline Transportation Systems for Liquid
Hydrocarbons and Other Liquids
Gas Transmission and Distribution Systems
DNV-ST-F101
Submarine pipeline systems
BS PD 8010-2
ASME B31.4
Application
Onshore and offshore steel
pipeline systems
Offshore steel pipeline systems
Onshore and offshore steel
pipeline systems
Onshore and offshore steel
pipeline systems
Offshore steel pipeline systems
2.1.2.4 Other Codes and National Standards may be used by agreement or where specified by local regulatory
requirements.
2.1.2.5 Where the latest revision of a Code or Standard is not used, a gap analysis may be required to assess
the impact of the latest revision of the applicable Code or Standard.
Section 3:Offshore installation safety
3.1
General
3.1.1
Objectives
3.1.1.1 Consideration of how the pipeline system interfaces with the overall installation safety philosophy is
central to the design of subsea pipelines within the vicinity of offshore installations (fixed or floating structures and
facilities). In general, the pipeline design standards listed in Table 2.2 Codes and Standards include increased
safety margins and requirements to ensure a higher margin of safety at such locations. National Regulations also
generally require an enhanced level of safety at these locations. The following Sections are intended to
supplement the standards and Regulations for a limited number of aspects only and are not intended as
comprehensive guidance for pipeline safety design.
3.1.2
Selection of safety factors for normally unattended installations
3.1.2.1 Pipelines and risers in the vicinity of normally attended offshore installations normally must be designed
with a high safety margin (generally higher than the subsea pipeline remote from the installation). This higher
safety margin is based primarily upon the higher consequences of failure and the risk to life at normally attended
facilities.
3.1.2.2 For normally unattended installations (NUIs) where a limited number of personnel attend the installation
infrequently for maintenance and inspection purposes and where the installation has no facilities for
accommodation, the requirement to provide a higher margin of safety for the riser may be challenged. In such a
scenario, a lower safety margin for pipelines and risers within the vicinity of NUIs may only be considered where
a comprehensive risk assessment has been performed. This risk assessment should consider the following:
•
•
•
risks to any personnel that may be on or in the vicinity of the installation (including short duration
temporary periods), accounting for the potential for escalation of accident events;
environmental impacts from a release of pipeline contents due to loss-of-containment;
risks to stakeholder reputation, assets and production continuity.
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Chapter 1 – Section 2
3.1.3
Potential utilisation of HIPPS and HIPPS fortified zones
3.1.3.1 It may be the case that the implications of providing a pipeline that is fully rated for pressure protection
would result in a pipeline that is not practical or is considered to be of a prohibitive cost for the proposed project
to be undertaken. This can occur when a new higher-pressure system/pipeline is planned to tie-in to existing
extensive lower-pressure rated systems. In these scenarios the utilisation of a high integrity pressure protection
system (HIPPS) may be appropriate. The utilisation of any proposed HIPPS must be carefully considered and be
robustly justified by a documented risk assessment. The risk assessment should consider the following:
•
•
•
risks to any personnel that may be on or in the vicinity of the installation, accounting for the potential
for escalation of accident events;
environmental impacts from a release of pipeline contents due to loss-of-containment;
risks to stakeholder reputation, assets and production continuity.
3.1.3.2 Where a HIPPS has been adopted by the project to protect the pipeline system from high pressures and
where not specified by the primary pipeline standard, the required reliability (normally defined in terms of integrity
level, IL) of the HIPPS system should be determined. This should be based on the conclusion of the above
referenced risk assessment and a documented integrity level (IL) assessment. As part of the IL assessment, a
documented safety integrity level (SIL) and an environmental integrity level (EIL), plus any other defined integrity
levels for the HIPPS, should be defined and documented. These assessments should be in line with the guidance
given in recognised standards such as IEC 61508 Functional safety of electrical/electronic/programmable
electronic safety related systems, IEC 61511 Functional Safety – Safety Instrumented Systems for the Process
Industry Sector or API RP 14 C Recommended Practice for Analysis, Design, Installation, and Testing of Basic
Surface Safety Systems for Offshore Production Platforms. Providing that it is demonstrated that the HIPPS has
the required reliability based on the conducted risk assessments and integrity level assessment, the downstream
pipeline may be designed based on the HIPPS set-point.
3.1.3.3 Where a HIPPS system is proposed, it is recommended to specify fortified protection zones (areas of
increased pressure containment capacity) immediately downstream of the HIPPS and at locations of high
criticality, such as close to normally attended installations. To determine the requirement and locations for
fortified zones, a detailed risk assessment should be performed and documented. The length and design
pressure of any fortified zones should be determined on a case-by-case basis.
3.1.3.4 Figure 3.1 Fortified zones illustrates a scenario where two fortified zones may be required, each with its
own design requirements.
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Chapter 1 – Section 3
Figure 3.1 Fortified zones
3.1.3.5 The example illustrated in Figure 3.1 Fortified zones includes two fortified zones. The design philosophy
for each fortified zone is as follows:
•
•
Fortified Zone A – The design scenario for Fortified Zone A is a failure of the well control system and
exposure of the HIPPS and a defined length of pipeline immediately downstream of the HIPPS to full
CITHP. The length of Fortified Zone A should be determined based on the speed of pressure build-up
from the well location and the time required for the HIPPS valves to close. The design pressure for
Fortified Zone A should be equal to the shut-in pressure (CITHP).
Fortified Zone B – The design scenario for Fortified Zone B is the failure on demand of the HIPPS
system. The length and design pressure of Fortified Zone B should be determined based on the
results of a risk assessment. Typically, this fortified zone would include the riser and a length of
subsea pipeline upstream of the riser to a point where the consequence of failure would be acceptable
to the safety and other defined integrity requirements of the facilities and any nearby infrastructure.
The design pressure for Fortified Zone B (if required) may be defined as either:
o Equal to the shut-in pressure;
o Greater than the maximum pipeline burst pressure of the non-fortified pipeline segment; or
o Based on a probabilistic assessment to demonstrate with a high degree of confidence that the
non-fortified pipeline segment would fail prior to the fortified zone pipe, and that consequences
of a failure in the non-fortified pipeline segment are acceptable.
3.1.3.6 In some cases, the ratio of shut-in pressure (upstream of HIPPS) to the pipeline design pressure
(downstream of the HIPPS) may be very high at the start of life and therefore the required integrity of the HIPPS
may be high at the start of life. If the shut-in pressure is expected to reduce over time, this may be taken into
consideration in the design of the HIPPS.
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Chapter 1 – Section 3
3.1.4
Subsea isolation valves
3.1.4.1 Subsea isolation valves (SSIVs) are used to isolate an offshore installation from large hydrocarbon
inventories in the event of a pipeline or riser leak or rupture on or very close to the installation. The primary
purpose of the SSIV is to minimise the potential volume and duration of any hydrocarbon release between the
SSIV and the riser ESDV.
3.1.4.2 Typically, long large-diameter gas pipelines connecting to a manned facility require an SSIV. However,
the decision on whether an SSIV is required for a given pipeline should be based on the results of a risk
assessment.
3.1.4.3 A positioning study for the SSIV should be performed to determine an appropriate location which
minimises the risks to the installation. Typical analysed scenarios include:
•
Dropped objects from the installation impacting the pipeline outboard of the SSIV
o The SSIV should be positioned at a sufficient distance from the installation to minimise the risk
of dropped objects from the installation (including transfer of objects from supply vessels)
potentially resulting in an uncontrolled release of the entire outboard pipeline inventory.
•
Riser release resulting in a jet fire
o The SSIV should be positioned sufficiently close to the installation to minimise the inventory
that can be released in the event of rupture of the riser. Analysis should be performed to
quantify the jet fire durations for various sizes of riser rupture, including consideration given to
SSIV passing rates, and whether the resulting duration and length of jet flame could result in
escalation of the incident (loss of structural integrity of the installation, loss-of-containment from
adjacent risers, etc.).
•
Flammable gas cloud from a subsea loss-of-containment of the pipeline
o The SSIV should be positioned at a sufficient distance from the installation to minimise the risk
of a large-scale toxic or flammable gas cloud reaching the installation.
3.1.4.4 Clearly, there may be several competing risk criteria which either benefit from or are adversely impacted
by moving the SSIV closer to or further away from the installation. Consequently, the position of the SSIV should
be selected based on the location that results in the lowest cumulative risk.
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Chapter 1 – Section 4
Section 4:Pipeline analysis
4.1
General
4.1.1
Objective
4.1.1.1 The guidance provided in the following Sections is intended to supplement normative requirements
specified in International Codes and Standards. In case of any conflict between the below guidance and the
requirements of the selected primary design standard, the requirements of the primary design standard take
precedence.
4.2
Use of pressure and temperature for design
4.2.1
General
4.2.1.1 Table 4.1 Application of pressure and temperature for design summarises the parameters to be used for
different aspects of pipeline design. In general, design capacity assessments should be performed considering
the maximum pressure and temperature that the pipeline may experience so that the suitability of the pipeline to
safely operate under design conditions is demonstrated. For time-dependent failure modes, such as fatigue,
which do not determine the instantaneous capacity of the pipeline, benefit may be taken of using operational
parameters provided they are conservatively selected.
Table 4.1
Application of pressure and temperature for design
Analysis Type
Pressure
containment
Collapse and
propagation
buckling
Cathodic
protection
Fatigue
Expansion
Spool/riser stress
analysis
Buckling
Material selection
Max Design
Pressure
(see Note 1)
x
Max Design
Temp (see
Note 1)
x
Min Design
Temp
Operating
Pressure
Operating Temp
(x) see Note 2
x
x
(x) see Note
3
x
x
(x) see Note 3
(x) see Note 3
x
x
(x) see Note 4
x
x
x
x
(x) see Note
x
x
5
Note 1. Where maximum design pressure is utilised for a given assessment, it is acceptable to base the
design on the maximum associated temperature in combination with the maximum design pressure.
Note 2. Collapse and propagation buckling assessment should be based on the minimum pipeline internal
pressure that can be sustained. In the as-laid condition, this pressure is normally zero unless the pipeline is
free-flooded during installation.
Note 3. Fatigue assessment should include design pressure and temperature cycles if these are expected to
occur.
Note 4. Minimum design temperature should be used to determine maximum pipeline end contraction for
spool design.
Note 5. The maximum design pressure should be used to determine partial pressures of constituent gases
used for material selection.
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Chapter 1 – Section 4
4.2.1.2 It is generally conservative to base a pipeline capacity calculation on the combination of maximum
design pressure and maximum design temperature. Where required, this may be refined by assessing design
pressure and design temperature cases separately, in each case considering the pressure or temperature
associated with the design parameter. The maximum associated temperature or pressure should be determined
based on an assessment of the conditions which result in the maximum design parameter.
4.2.2
Design pressure
4.2.2.1 Pipeline Codes and standards generally define the following pressures which need to be considered
during the design of a pipeline system:
•
•
•
Design pressure – Normally defined as greater than or equal to the maximum allowable operating
pressure (MAOP).
Maximum allowable operating pressure (MAOP) – Normally defined based on the maximum
expected steady-state operating pressure plus the operating tolerance value of the Pipeline Control
System (PCS). Alternatively, where the design pressure is defined, the MAOP is equal to the design
pressure minus the operating tolerance value of the PCS. In either case, the MAOP is the upper limit
cut-off of the PCS.
Incidental pressure – Normally defined as a margin above the design pressure to account for transient
excursions above the MAOP and to allow for the operating tolerance of the Pipeline Safety System
(PSS). The set-point of the PSS is normally at a pressure equal to the incidental pressure minus the
operating tolerance of the PSS. Note that some standards require design and pressure testing to be
based on incidental pressure while others do not (however, limitations on the magnitude of allowable
incidental pressure are imposed). Care should be taken to ensure an approach consistent with the
requirements of the primary design standard.
4.2.2.2 The pipeline design pressure should be greater than or equal to the maximum operating pressure of the
pipeline. In many cases it may also be equal to the CITHP of the production wells; in cases where the design
pressure is less than the CITHP, then sufficiently reliable protection measures such as a HIPPS should be
implemented to protect the pipeline from over pressurisation. Discussion on HIPPS fortified riser zones is
provided in Section 2.1.3 Potential utilisation of HIPPS and HIPPS fortified zones.
4.2.3
Maximum design temperature
4.2.3.1 The maximum design temperature of the pipeline should be the highest possible temperature that the
pipe wall will experience due to operational and environmental sources of temperature (exposed areas of
pipelines such as risers or onshore sections at landfalls may be exposed to solar radiation, which can lead to
higher pipe wall temperatures than from operation).
4.2.3.2 Since elevated temperature is a primary source of loading in a pipeline system and may also derate
material tensile properties (reduction of yield stress and tensile strength at elevated temperatures), the definition
of maximum design temperature for a pipeline system should be considered carefully as it is a significant factor in
the optimisation of the pipeline design. Where the maximum design temperature is not clearly defined for the
pipeline system as a function of pipeline length, this can lead to inconsistency of approach for design of pipeline
elements remote from the inlet.
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4.2.3.3 Figure 4.1 Temperature profiles illustrates the following three scenarios which are normally encountered
in pipeline design:
•
•
•
Scenario A – In Scenario A, the pipeline system design temperature at the inlet (KP 0) is used for
design calculations at the location of interest (KP 3).
Scenario B – The approach in Scenario A conservatively assumes that the pipeline system design
temperature at the inlet (KP 0) may be reached at KP 3. Scenario B shows an approach where design
calculations at the location of interest (KP 3) are based on the location-specific design temperature,
which is interpolated from a design temperature profile calculated based on flow assurance analyses.
In such case, the design should ensure that the calculated design temperature profile is based on
conservative inputs to the flow assurance analyses.
Scenario C – In Scenario C, design calculations at the location of interest (KP 3) are based on the
location-specific operating temperature (based on the operating temperature profile). Note that this
approach results in an unconservative design, as the operating temperature is lower than the
realistically achievable design temperature at the location of interest. The design may be refined by
assessing design pressure and design temperature cases separately, in each case considering the
pressure or temperature associated with the design parameter.
Figure 4.1 Temperature profiles
4.2.3.4 Minimum design temperature as a function of pipeline length and/or pipeline system element (i.e. riser,
tie-in spool, in-line valve structures, pipeline, etc.) should be clearly defined and documented.
4.3
Material properties and use of actual test results in design/analysis
4.3.1
Objectives
4.3.1.1 The purpose of this section is to provide guidance on addressing the possible scenario whereby one or
other design case requires mechanical strength values higher than the specified minima.
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4.3.2
Pipelines
4.3.2.1 The material manufacturing process is designed to achieve the specified minimum strength values with
high reliability to avoid rejection of material. Typically, the mill data will show that the mean values of yield
strength and ultimate tensile strength from a large number of tensile testing results form a normal distribution with
the mean values significantly above their respective specified minimum values.
4.3.2.2 The application standard/design Code and its accompanying material specification stipulate the testing
frequency for chemical analysis and mechanical properties. This is the basis on which material certificates
containing the test results are produced. The chemical composition is normally analysed per heat (or cast, ladle)
of molten steel, which represents a large tonnage of steel (typically 100 to 300 tonnes) capable of producing a
large number of products (e.g. pipes or plates).
4.3.2.3 The mechanical testing frequency is normally based on the combination of test unit (sometimes the
term ‘batch’ is used instead of test unit), number of pipes and cold-expansion ratio.
4.3.2.4 A test unit or batch for line pipe manufacture is typically based on the following essential variables:
•
•
•
•
•
•
Heat (or cast);
Outside diameter;
Wall thickness;
Pipe manufacturing process;
Pipe manufacturing conditions;
Plates made to the same hot rolling practice (for seam-welded pipes).
4.3.2.5 The EN ISO 3183 (API SPEC 5L) line pipe material standard defines a ‘test unit’ as follows:
‘Prescribed quantity of pipe that is made to the same specified outside diameter and specified wall thickness,
from coils/plates produced by the same hot rolling practice (as applicable to welded pipe), by the same pipemanufacturing process from the same heat and under the same pipe manufacturing conditions.’
4.3.2.6 Normally, the specified minimum values of mechanical properties such as yield stress and ultimate
tensile strength are adopted in design calculations. However, where the primary design Code is silent on the
matter, it is reasonable to use statistically derived lower bound actual material properties (based on production
tests) for design purposes. This may be applied to room temperature or elevated temperature properties and
applications. Design codes for room temperature specify room temperature properties. For elevated temperature,
codes specify design strengths either directly through measurement at the design temperature or by the derating
of room temperature values. For elevated temperature applications, the approach described in this recommended
practice may be followed using either elevated temperature results or room temperature results with subsequent
derating, as appropriate to the governing code.
4.3.2.7 A statistical approach may be used to determine the lower bound mechanical strength which may be
used in design (where not prohibited by the primary design Code).
4.3.2.8 The statistical derivation of the lower bound mechanical strength should be based on a 97,5 per cent
probability that the material tensile properties exceed the required design strength (consistent with two standard
deviations from the population mean based on a normal distribution) with 95 per cent confidence.
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4.3.2.9 If the population standard deviation is known from the mill, it is acceptable to perform a statistical
analysis to estimate the lower bound population mean (based on sample mean and sample size) and to use the
known population standard deviation to derive the lower bound mechanical strength. However, if the population
standard deviation is not known (i.e., only the sample standard deviation can be determined), the upper bound
population standard deviation should be statistically estimated (based on the sample standard deviation and
sample size) and used to derive the lower bound mechanical strength.
4.3.2.10 The test results reported on the material certificates from the different test units/batches should be
compliant with the testing frequency of the governing application standard and/or material standard. The test
results should be grouped for statistical analysis, with those in each analysis group having the following in
common:
•
•
•
•
•
•
•
•
•
Manufacturer;
Manufacturing site;
Manufacturing specification (which is normally based on a particular pipe manufacturing process, etc.);
Manufacturing procedure qualification (MPQ);
Cold-expansion ratio (if applicable);
Grade;
Supply condition (e.g. normalised being distinct from thermomechanically controlled processing);
Wall thickness;
Nominal diameter.
4.3.2.11 Test results from existing material certificates may be sufficient for this statistical analysis. However,
additional testing may be necessary to achieve greater confidence in results and/or to facilitate witnessing of
tests by the user or user's representative.
4.3.2.12 Such additional testing shall represent the full range of material to be used for the project under
consideration (i.e. tests from every test unit to be used for the project under consideration). Preferential selection
of test samples from more favourable test units (i.e. those with higher strength results) is potentially unsafe and
shall be avoided.
4.3.2.13 In design based on specified minimum strength values, the requirements for weld joint strength and the
corresponding tests vary according to the governing codes. For example, ultimate tensile strength from crossweld tensile tests and yield strength from all-weld tensile tests would typically need to meet or over-match the
specified minimum values of the base metal. In the situation of needing to achieve higher-than-specified strength
values to meet new design requirements, not only the base metal, but also the welded joints need to comply with
these new requirements.
4.3.2.14 At least two possible scenarios may arise in the above context. Firstly, that base metal has been
procured, but welding consumable selection and welding procedure qualification have not yet taken place, and
secondly that base metal has been procured, welding consumables have been selected and welding procedures
have been qualified. The first of these scenarios is easier to address than the second. Welding consumables are
to be selected and welding procedures qualified using the new criteria. Welding consumables with minimum
specified strength levels equal to or greater than the new higher strength requirements are to be specified and
certified, and the welding procedure qualification requirements are to meet the new requirements. The second
scenario is more difficult to address but is more likely. In this scenario, certificates for all welding consumable
batches used in production and all PQRs are to be checked to verify that the reported strength values meet the
new requirements. In addition, due to the range of variations of the second scenario, including differences in
design codes and welding codes, the specific actions to gain confidence that the welded joint strengths achieve
the new requirements are to be agreed on a case-by-case basis.
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4.3.2.15 It should be noted that some pipeline design standards prohibit the use of mechanical properties higher
than the specified minimum values for design. Any deviation from the requirements specified in the primary
design Code should be fully justified, documented, and formally accepted by all stakeholders.
4.3.2.16 Historical mill data and accompanying statistics (i.e. not project testing results) may be useful secondary
information to understand the typical strength values from relevant manufacturers; however, the strength of the
batches supplied for the specific project are of primary interest and it is these that are the subject of the analysis
methods described in this Section.
4.3.3
Structural Applications
4.3.3.1 Although this document is an RP for pipelines, the user may wish to follow a similar approach for steel
plate for structural applications. The testing frequency in the applicable structural standards shall be used for the
analysis described in this Section.
4.3.3.2 Examples of testing frequencies based on test units are defined in the following standards for structural
steels: EN 10021, EN 10025 and EN 10225.
4.3.3.3 The test results reported on the material certificates from the different test units/batches should be
compliant with the testing frequency of the governing application standard and/or material standard. The test
results should be grouped for analysis, with those in each analysis group having the following in common:
•
•
•
•
•
•
•
4.3.4
Manufacturer;
Manufacturing site;
Grade;
Manufacturing specification (which specifies the particular manufacturing process, chemistry, etc. used
to achieve the grade requirements, and has been proven by a unique manufacturing procedure
qualification (MPQ));
Supply condition (e.g. normalising being distinct from thermomechanically controlled processing);
Plate thickness or a narrow range of thicknesses, to be agreed;
Agreed weight.
Pipeline components
4.3.4.1 For pipeline components for which a statistically significant number of mechanical tests is unavailable
(due to a limited number of components), such as bulkheads and flanges, it is recommended to always use the
specified minimum values for design. It is not acceptable to adopt mechanical properties from tests unless more
than five test results are available. If more than five test results are available, the guidance in Section 4.3.2
Material properties and use of actual test results in design/analysis may be applied.
4.4
Riser design
4.4.1
Objectives
4.4.1.1 Risers provide the connection between the subsea pipeline and the installation’s topside piping. The
Codes and standards listed in Section 2.1.2 Application of standards include normative requirements which
should be applied for the design of rigid steel risers. The following additional recommendations are provided for
the design and analysis of static rigid steel risers clamped to offshore fixed or floating structures.
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4.4.2
General arrangements
4.4.2.1 The location of a riser on an installation should be selected to minimise the risk posed to the installation
from the riser and subsea pipeline. The following principles should be followed in the selection of the riser
location:
•
•
•
•
Minimise the probability of damage to the riser – To minimise the risk of accidental damage to the
riser, it is recommended to locate the riser within the structural envelope close to a primary vertical
structural member. Where it is not possible to locate the riser within the structural envelope, additional
protection frames may be required. A quantitative risk assessment should be performed to determine if
any mitigating measures are required.
Minimise the consequences of riser failure to the safety of the host installation – Careful
consideration should be given to the nature of the fluid contained within the riser and the escalation
consequences following a loss of fluid containment. For example, proximity to sources of ignition,
accommodation modules, escape routes, etc. A quantitative risk assessment should be performed to
determine if any mitigating measures are required.
Minimise the risk to the subsea pipeline from dropped objects – The subsea pipeline approach
route to the riser location on the installation should be evaluated. If the route passes beneath a
platform crane used for loading and offloading supply vessels, the risk of dropped objects to the
pipeline may be unacceptably high. A quantitative risk assessment should be performed to determine
if any mitigating measures are required.
ESDV position – The riser ESDV should be placed as low as practically possible on the installation so
that the length of riser is minimised. The route of the riser to the ESDV should be minimised to avoid
long horizontal sections of riser traversing beneath the deck. These requirements are to limit the
exposure of the installation to the pipeline inventory.
4.4.2.2 It is acknowledged that rationalisation of elements of an installation design may impose constraints upon
the credible riser locations; however, the probability and consequences of riser and pipeline failure at the
installation should be quantified and demonstrated to be ALARP and meet acceptable risk targets.
4.4.3
Riser loads
4.4.3.1 As a minimum, the following sources of loading should be considered in the design of a rigid steel riser:
•
•
•
•
•
•
•
4.4.4
Self-weight and buoyancy;
Operational loads (pressure, temperature, slugging);
Environmental loading (wind, waves, current, seismic, ice);
Platform displacements;
Tie-in loads (subsea and topside interface loading);
Marine growth;
Accidental loads (ship impact, dropped objects).
Riser strength analysis
4.4.4.1 The static strength (combined stress, local buckling and global buckling) of the riser should be
demonstrated to meet the normative requirements as specified by the primary design Code selected for the riser,
including the consideration of wall thickness tolerance, bend thinning (for riser bends) and corrosion allowance.
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4.4.4.2 The load cases that should be assessed in the riser strength analysis are outlined in Table 4.3 Table
Riser load cases.
Table 4.3
Riser load cases
Load Case
Pressure
containment
Combined
stress (SOL)
Combined
stress (EOL)
Global buckling
(SOL)
Global buckling
(EOL)
Fatigue
Marine
Growth
-
Environmental
RP
-
Pressure
Temperature
Riser Support
Displacements
-
Max design
Max design
-
10−3
Max design
Max design
Max
10−3
Max design
Max design
-
-
Max design
Max design
Combinations
(see Note 4)
Combinations
(see Note 4)
-
Max
-
Max design
Max design
-
Max
Scatter (see
Note 1)
10−5
Operating
Operating
Scatter (see
Note 5)
-
Survival (see
Max
See Note 3
See Note 3
Note 2)
Note 1. Environmental scatter data should be representative of long-term environmental conditions and have
sufficient resolution to cover the entire water depth.
Note 2. Survival case may be assessed on a project-specific basis.
Note 3. For the survival case, operating pressure and temperature should be used unless it can be
demonstrated that established procedures are in place, and in readiness, to reduce the operating pressure
and temperature in advance of a survival event.
Note 4. Worst case from a range of directional displacements should be adopted.
Note 5. Scatter of platform displacements may or may not be in phase with the environmental scatter data.
4.4.4.3 Sensitivity analysis should be performed to confirm that the riser design remains compliant with Code
requirements when considering the effect of marine growth and potential fouling of riser guide gaps leading to a
change in restraint at the guides.
4.4.5
Fatigue
4.4.5.1 The Codes and standards listed in Section 2.1.2 Application of standards include normative
requirements regarding allowable fatigue damage for risers. Where the primary design standard for the riser does
not include guidance for fatigue analysis of risers, the following criteria may be adopted:
•
•
•
•
18
Allowable fatigue damage should be limited to 0,1, based on the assumption that the riser is safety
critical and not subjected to a regular NDE inspection.
Design SN curves (based on 2,3 per cent probability of failure) should be adopted for fatigue damage
calculation.
SN curves in seawater with cathodic protection should be adopted for all riser weld caps (submerged,
splash zone and above).
SN curves for riser weld roots should be applicable for the fluid transported by the pipeline. Special
consideration should be given to sour service.
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4.4.5.2 As a minimum, fatigue due to the following sources should be considered and quantified:
•
Operational loads:
o Fluctuations of pressure and temperature – both due to normal operational fluctuations and due
to start-up/shutdown cycles. In the absence of predicted operational fluctuations, conservative
assumptions should be made and documented.
o Slug loads.
o Platform displacements.
•
Environmental loads:
o Direct wave loading.
o Wave slamming.
o VIV due to wind and waves.
4.4.5.3 The susceptibility of the riser to VIV should be investigated and the supports should be appropriately
spaced so that VIV is avoided. Guide supports should be considered as ‘pinned’ supports unless analysis has
been performed to demonstrate a greater level of restraint.
4.4.6
Spare riser activation
4.4.6.1 Spare risers may be installed during construction of fixed platform jackets to facilitate the tie-in of future
field developments over the life of the installation. The design of a spare riser is typically performed without full
knowledge of the design conditions of the future field (i.e. fluid composition, design pressure and temperature,
design life, etc.).
4.4.6.2 Prior to operating an existing spare riser, analysis is required to demonstrate that it will be suitable for
the specific field development in accordance with a design Code current at the time of operation. Existing risers
designed in accordance with superseded design Codes should be assessed to identify any gaps between the
legacy and current Code requirements, and new analysis performed where necessary.
4.4.6.3 Analysis should be performed to demonstrate suitability of the riser for the imposed tie-in loads, as well
as a fatigue analysis to demonstrate suitability for the intended operating design life. The fatigue assessment
should include fatigue damage accrued prior to operation of the riser in addition to fatigue damage predicted
during the planned operational life of the riser.
4.4.6.4 Prior to operating an existing spare riser, a full integrity inspection should be performed to confirm the
riser condition which should be considered in the suitability analysis and to serve as a base line for future
assessments.
4.5
Pipeline expansion
4.5.1
General
4.5.1.1 Pipeline expansion and contraction due to differences in temperatures and pressures between
installation and operation conditions should be accounted for in the design of interfaces at pipeline ends. Whilst
the magnitude of expansion may not form a pass/fail criterion itself, it is a key input to the design of connecting
infrastructure such as spools, PLETs with sliding frames and pipe-in-pipe bulkheads.
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4.5.2
Pipeline end expansion
4.5.2.1 Expansion analysis should be performed based on the pipeline design temperature or the design
temperature profile, unless it can be demonstrated that adequate safeguards are in place to ensure that the
maximum operating temperature will not be exceeded. Use of design temperature is necessary to ensure that the
adjoining infrastructure, such as spools which are typically optimised (relatively highly utilised), are designed to
safely accommodate the maximum load they may be subjected to during the design life.
4.5.2.2 The magnitude of pipeline end expansion is a function of the following and, provided that conservative
parameters are selected, it is not necessary to include any additional safety factors in the derivation of the
magnitude of pipeline end expansions:
•
•
•
•
•
•
•
Axial soil friction;
Pipeline length;
Pipe cross-sectional properties (diameter, wall thickness and density of pipe steel and coatings, and
density of contents);
Differential temperature (maximum design temperature minus pipeline installation temperature);
Differential pressure (internal pressure minus external pressure);
Bathymetry;
Interface loads.
4.5.2.3 The above listed parameters, and the variability of these parameters as a function of pipeline length,
should be accounted for in the calculation of the pipeline end expansion, which may be determined analytically
from first principals or by using FEA methods.
4.5.2.4 The design expansion level should be calculated using the lower bound soil properties unless it can be
demonstrated that lower bound properties are not applicable.
4.5.2.5 For calculation of loads to be applied at pipe-in-pipe bulkheads, an upper bound friction coefficient
should be selected. This minimises the anchor length and results in peak loading on the bulkhead. Refer to
Section 5 Pipe-in-pipe systems for further guidance on pipe-in-pipe and bulkhead design.
4.5.2.6 Interface loads (reactions to pipe expansion) should be based on lower bound estimates of the interface
resistance to expansion.
4.5.2.7 Where the pipeline is designed with planned buckles (with a high level of reliability), the anchor length
from the pipe free end may consider the effect of the first planned buckle.
4.5.2.8 Where the pipeline is designed to accommodate unplanned buckles, the anchor length from the pipe
free end should be based on the distance required to achieve the fully restrained effective axial force.
4.5.2.9 Figure 4.2 Soil anchor point scenarios provides examples of how the above principles may be applied in
the calculation of pipeline end expansion for the same pipeline cross-section, operating conditions and soil
parameters. This figure is included to provide examples only and is not intended to comprehensively cover all
possible scenarios.
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Figure 4.2 Soil anchor point scenarios
4.5.2.10 A description of each scenario presented in Figure 4.2 Soil anchor point scenarios is given below:
•
•
•
4.5.3
Point A – Soil anchor point A considers lower bound axial soil friction acting over a length to achieve
the fully constrained effective axial force in the pipeline. Provided that there are no significant seabed
slopes towards the free end and no axial tension is applied at the free end, calculation of expansion
utilising this method is conservative.
Point B – Soil anchor point B is calculated in the same way as point A; however, the presence of the
first planned buckle has been accounted for in the calculation of the effective axial force profile of the
pipeline. This results in a shorter distance to the anchor point from the pipeline free end and therefore
would result in a lower predicted pipeline end expansion than Point A.
Point C – Soil anchor point C is calculated in the same way as point A; however, the sliding resistance
of a structure (e.g. PLET) at the pipe free end has been taken into consideration. The consideration of
the structure’s resistance to sliding results in a shorter anchor length and would result in a lower
predicted expansion than point A.
o Alternatively, a non-linear spring may be used to represent the response of the connecting
structure or spool at the pipeline free end. A lower bound structural stiffness should be
assumed to ensure a conservative estimate of end expansion.
Walking
4.5.3.1 For short pipelines where a soil anchor is not reached along the pipeline length, the expansion analysis
may be combined with the walking analysis. While the design expansion values should be calculated using the
design temperature, walking may be evaluated by considering the anticipated cycles in operation (based on flow
assurance studies of operational scenarios).
4.5.3.2 Where a pipeline is found to be susceptible to walking, mitigation may be designed and implemented
prior to operation of the pipeline, or alternatively an inspection plan may be developed (based on the predicted
rate of walking) to monitor the pipeline walking behaviour over time. An acceptable walking rate should be
established, above which mitigations should be implemented to ensure that walking is controlled to maintain
accumulated pipe end displacements within acceptable levels.
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4.6
Tie-in spool design
4.6.1
General
4.6.1.1 Tie-in spools are utilised to provide the connection between pipelines and fixed infrastructure, or
between adjacent pieces of fixed infrastructure. The spool functions to accommodate expansions/displacements
so that acceptable loads are transferred to the infrastructure tie-in points.
4.6.1.2 Subsea tie-in spools may be horizontal and designed to move across the seabed, or they may be
oriented in the vertical plane and designed to span between adjacent structures. Vertical spools are more
commonly utilised in deep water between structures where diverless connections are required and where there
are no fishing activities.
Figure 1.6.3 Vertical and horizontal spools
4.6.1.3 The cross-section design of tie-in spools should be performed in accordance with the nominated primary
design Code. The spool loads (forces and moments) to be considered for cross-section design should be
determined based on a comprehensive analysis of the spool. The following Sections provided guidance on
modelling tie-in spools to determine spool loads.
4.6.2
Modelling approach
4.6.2.1 Where the spool connects to a subsea pipeline, different approaches may be adopted to model the
interface with the subsea pipeline as follows:
(a) Pipeline is not modelled – Where the pipeline is not modelled, the pipeline end expansion (as described
in Section 3.5.2 Pipeline end expansion) should be calculated separately and a displacement equal to
the calculated end expansion should be applied at the pipeline/spool connection. Conservatively, the
rotation of the connection point may be fixed. Conservatism may be reduced by implementing a spring
with rotational stiffness equal to the pipeline bending stiffness. Alternatively, a short length of the
pipeline may be modelled (to capture structural continuity).
(b) Short length of pipeline is modelled – Where only a short length of the pipeline is modelled to capture
structural continuity (primarily bending stiffness) between the spool and pipeline, it is recommended that
the end expansion should be applied as a displacement at the last point of the modelled pipeline. The
length of pipeline modelled should be such that the bending moment in the pipeline has returned to a
nominal level at the tie-in point to the spool.
(c) Pipeline is modelled until the soil anchor point – Where the pipeline and spool are modelled as a
system, it is recommended to model the pipeline until beyond the soil anchor point, considering the
lower bound axial soil friction (in the absence of the spool) to ensure that the maximum pipeline end
expansion is applied to the tie-in spool under all load cases. The pipeline should be modelled as fully
restrained at the soil anchor point.
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4.6.2.2 In addition to metrology tolerance, fabrication tolerances and installation tolerances of subsea structures
and pipeline end connections should be accounted for to ensure a robust tie-in spool design which will be able to
safely accommodate expansion loads for extreme combinations of actual connection point locations (i.e.
dimensions of the spool may be longer or shorter depending upon the actual tie-in points). Therefore, it is
generally required to create sensitivity models that consider extreme layout combinations to confirm acceptability
of the spool design.
4.6.2.3 The analysis of spools covered with mattresses should take account of the additional weight of the
mattress on the spool. This will increase the axial and lateral soil resistances due to the increased weight and
may also lead to increased friction factors if further embedment of the spool occurs. In the absence of project
data, the applied mattress weight to the pipeline can be estimated to be equivalent to a mattress width of two to
three times the pipeline outer diameter.
4.6.3
Tie-in spool loads
4.6.3.1 A load case matrix for stress and fatigue analysis of the spool should be designed and should include,
as a minimum, the following aspects:
•
Functional loads – The following functional loads should be assessed and the associated range of
operating fluid densities for each case should also be considered:
o
o
o
o
•
Environmental conditions – The following environmental conditions should be considered:
o
o
o
o
•
•
Leak test pressure;
Strength test pressure;
Maximum design pressure and temperature;
Slugging loads (if applicable).
Ambient temperature – The maximum and minimum ambient temperature should be
considered, and the worst case selected in combination with each functional load case.
Ambient external pressure – The maximum and minimum external pressure should be
considered, and the worst case selected for the load case and capacity aspect being assessed
(e.g. wall thickness, local buckling, collapse, etc.).
Environmental loading – Where the spool is exposed, loads due to drag, lift, inertia and vortex
induced vibrations (where the spool is spanning) should be considered. These loads should be
applied in combination with the design expansion conditions. Furthermore, the spool and
adjacent pipeline should be designed for absolute stability. If the spool and pipeline do not
satisfy absolute stability criteria, mitigations such as concrete mattresses should be provided to
shield the spool from environmental loads.

Environmental loads are not required to be applied in the spool analysis for cases where
the spool is shielded, such as under mattresses or GRP covers. However, in these
cases the protective element should be assessed to be stable under the considered
environmental loading.
Seismic loading – Where relevant, the spool should be designed to accommodate loads and
displacements due to seismic loading.
Soil conditions – Where the spool is in contact with the seabed, all combinations of upper bound and
lower bound axial and lateral soil resistance should be assessed (UB Lat/UB Axial, LB Lat/LB Axial,
UB Lat/LB Axial and LB Lat/UB Axial). Alternatively, where it can be demonstrated that axial and
lateral soil resistance are correlated, upper bound and lower bound soil resistance may be assessed.
Structure settlements – Settlement of connecting structures should be considered as imposed
displacements at connection points to the spool. Both short-term and long-term settlements should be
considered depending upon the scenario under consideration (e.g. start of life, end of life, etc.).
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•
•
•
Spool geometry – Extreme combinations of spool layout should be assessed to confirm that the
selected spool wall thicknesses will be acceptable for all possible spool geometries (considering the
geometry and size of end point target boxes).
Connection misalignment – Fabrication of the spool should be based upon the subsea metrology
survey which is used to define the position and heading of the connection points for the spool.
Although based on the as-built survey of the connection points, there may remain misalignment at the
connection points. Spool misalignment is due to both measurement inaccuracy in the subsea
metrology survey and tolerances of spool fabrication (normally much smaller in magnitude). The level
of allowable inaccuracy in the subsea metrology survey and the fabrication process should be defined
in project specifications and include both linear and angular measurements. Sensitivity of the spool
design to credible combinations of linear and angular misalignments at connection points should be
investigated and quantified.
Third-party interaction – Where spools are not protected, the risk of third-party interaction should be
assessed and where required the spool should be designed to account for pull-over and snagging
loads.
4.7
On-bottom stability
4.7.1
General
4.7.1.1 Environmental loads imparted to a pipeline from the action of waves and currents can result in horizontal
and vertical movement of subsea pipelines and other supporting infrastructure.
4.7.2
Pipeline stability
4.7.2.1 Surface laid pipelines may become unstable due to environmental loading and displace laterally across
the seabed. Typically, pipeline stability is assessed using a force-balance relationship or using methods which
permit varying degrees of pipeline lateral displacement.
4.7.2.2 Local geotechnical data and local directional metocean data may be used to optimise the required
pipeline weight. Many of the commonly used stability methodologies permit some level of pipeline movement,
which allows the pipeline weight requirements to be reduced. Where lateral displacement of the pipeline is
permitted, the following should be considered:
(a) The proximity of connections to other parts of the pipeline system should be assessed. No movement
due to environmental loads should be permitted at mechanical connections.
(b) The pipeline route survey should confirm that there are no seabed obstructions (such as boulders and
rocky outcrops) which would restrict free movement of the pipeline and result in localised stresses and
strains.
(c) Thought should be given as to whether the displacements are expected to accumulate over the design
life from repeated loading due to the design environmental load and also due to more frequent but less
severe environmental conditions.
4.7.3
Mattress stability
4.7.3.1 Concrete mattresses may be utilised for several reasons, including stabilisation of the pipeline,
protection from third-party interaction/dropped objects, separation at crossings and as pre-lay supports for
pipeline spans.
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4.7.3.2 The stability of the proposed concrete mattresses should be assessed to confirm that the mattresses will
remain in place under the design environmental conditions. Where stability of the mattresses during the design
environmental conditions cannot be demonstrated, the limiting environmental conditions should be determined.
Provided a risk assessment has been performed which confirms that the integrity of the pipeline will not be
compromised by temporary loss of the mattresses, an inspection strategy which is triggered by the limiting
environmental conditions may be implemented to survey the mattress locations and replace the mattresses if
necessary.
4.7.3.3 Mattress stability should be demonstrated for all cases where the mattress is exposed to environmental
loads (i.e. both temporary and permanent, where applicable). Temporary cases include pre-lay support and other
cases where the mattresses are to be subsequently permanently stabilised with a rock dump.
4.7.3.4 Temporary stability should be assessed using the most onerous combination of 1yr/10yr wave and
current loads (seasonal data may be utilised), while permanent stability should consider the most onerous
combination of 10yr/100yr wave and current loads. The applied loads on the mattresses should be calculated
using Morrison’s equations with drag, lift and inertia coefficients appropriate for the selected mattress.
4.7.3.5 The mattress stability assessment should demonstrate a suitable factor of safety against the following
failure modes:
•
•
•
•
Whole mattress uplift;
Whole mattress sliding;
Edge block uplift;
Edge block overturning.
4.7.3.6 In the absence of project-specific requirements, a minimum factor of safety of 1,5 may be adopted.
4.8
Spanning
4.8.1
General
4.8.1.1 Pipeline free-spans may be present when the pipeline is initially installed due to seabed undulations, or
may develop over the design life due to mobility of the seabed sediments or scour. DNV-RP-F105 provides RP to
calculate initial span screening length and to demonstrate acceptability of any spans longer than the screening
length.
4.8.1.2 The assessment of fatigue at pipeline spans should account for fatigue accumulated through the life of
the pipeline, including installation and operation, and fatigue damage accrued due to any previous spans at the
same location. In regions of persistent or reoccurring spans, it is recommended to implement a span health
monitoring strategy which should perform the following:
•
•
•
•
•
Plan and perform regular span inspection surveys;
Track span behaviour over successive inspection surveys;
For the duration between two successive surveys, calculate fatigue damage at each weld location;
Monitor total accumulated fatigue and the fatigue damage rate at each weld location;
Propose and implement mitigation measures where predicted fatigue life is unacceptably low.
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Chapter 1 – Sections 4 & 5
4.8.1.3 In cases where an unacceptably low fatigue life is calculated and/or where there is low confidence in the
evolution of the span length, rectification measures should be performed to reduce the rate of accumulating
fatigue damage to achieve an acceptable fatigue life. This may be achieved by reducing or eliminating the span
gap, by shielding the span from environmental loads or through application of VIV suppression measures such as
strakes.
4.8.1.4 The design of span rectification measures should take account of the interaction of the rectification with
the seabed and its evolution over time to avoid reasonably foreseeable additional interventions. For example, a
rectification arrangement that utilises grout bags may not be suitable for locations subject to significant storm
loadings, which can displace the grout bag supports. Similarly, for locations which are subject to seabed scour, a
protection arrangement involving fronded mattresses may be preferable to reduce the probability of span
reoccurrence.
4.8.1.5 Permanent ‘super-spans’ of significant length may be unavoidable for some pipelines which cross
canyons, continental shelves or other large subsea topographic features. Due to the high susceptibility of such
spans to fatigue damage, measures such as VIV suppression strakes may be deployed. Stricter fabrication
requirements, based on fatigue and fracture assessments, may also be imposed within these sections to improve
fatigue performance by limiting initial defect sizes and stress concentrations at girth welds. Consideration should
be given to the structural stability of the seabed at the span touch down points due to the large load that can be
applied at these locations from the pipeline span.
Section 5:Pipe-in-pipe Systems
5.1
General
5.1.1
Introduction
5.1.1.1 Subsea pipe-in-pipe systems are commonly used where a high level of insulation is required to minimise
heat loss from transported fluids. Other advantages of pipe-in-pipe systems are increased stability and increased
protection of the inner pipe from impact damage.
5.1.1.2 Typical pipe-in-pipe systems comprise the following elements:
•
•
•
•
•
Flowline – The inner pipe which contains the transported fluids.
Carrier pipe – The outer pipe which protects the flowline and annulus from the external environment.
Annulus – The space between the flowline and carrier pipe. This is typically filled with a highly efficient
dry insulation material.
o Note that the annulus pressure should be used as the external pressure acting upon the
flowline and the internal pressure acting upon the carrier pipe.
Centralisers – Typically polymer rings which are spaced at regular intervals and used to maintain a
radial gap between the flowline and the carrier pipe. The centralisers transfer loads between the two
pipes and protect the insulation from unacceptable levels of radial compression which may occur
during reeling and unreeling processes of a reeled pipe-in-pipe pipeline.
Bulkheads – Typically forged components which mechanically connect the flowline to the carrier pipe.
End bulkheads are located at the two ends of the pipeline. Some designs may include intermediate
bulkheads which are located at defined intervals along the pipeline.
5.1.1.3 Note that terminology for the flowline and carrier pipe (inner and outer pipes) may vary and therefore
terms of reference for the pipe-in-pipe design should be clearly defined at the outset of the design.
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5.1.1.4 The following sub-Sections provide guidance for the design and qualification of the structural elements
of the pipe-in-pipe system (flowline, carrier pipe, centralisers and bulkheads).
5.1.2
Pipe-in-pipe mechanical design and safety philosophy
5.1.2.1 The design safety philosophy should determine the required level of safety (quantified, for example, by
target probability of failure) for the combined pipe-in-pipe system, accounting for the consequences of structural
failure and loss-of-functionality (such as a leak in the inner pipe causing a loss of effectiveness of the insulation in
the annulus).
5.1.2.2 The primary purpose of the inner pipe is to contain the fluid and that of the carrier pipe is to protect and
preserve the dry insulation in the annulus. Therefore, this guidance recognises that there may be technical and
commercial incentives to optimise the design of a pipe-in-pipe system such that the inner and outer pipes have
different design levels of safety. For example, this may be achieved by selecting different materials and/or wall
thicknesses for the two pipes. If this approach is adopted, the aim and outcome of the design should be that the
level of safety of the combined pipe-in-pipe system is equivalent to, or exceeds, that of a hypothetical single pipe
pipeline carrying the same fluid and having the same consequences of loss-of-containment.
5.1.2.3 The design should also consider the risk of progressive structural failure of the pipe-in-pipe system. For
example, consider a pipe-in-pipe pipeline with a segment which lies within the safety zone of a manned platform.
Without an intermediate bulkhead providing a separation between the annulus within the safety zone and the
annulus outside the safety zone, a loss-of-containment of the inner pipe at a location outside the safety zone
could result in the fluid filling and pressurising the carrier pipe within the safety zone. If the carrier pipe were
optimised to adopt the same level of safety within and outside the safety zone, this would result in an
unacceptably high probability of failure of the carrier pipe within the safety zone.
5.1.2.4 If the design of the pipe-in-pipe system relies on the resistance contributions of both pipes, then the
design of both pipes should be based on the same level of safety. This is because the failure of one pipe leads to
an unacceptably high probability of failure of the other pipe, as there is no redundancy in the design.
5.1.2.5 Determination of required level of safety for the various components of a pipe-in-pipe system should
also ensure that risks of loss-of-functionality are fully documented and are acceptable.
5.1.2.6 In addition to the assessment of limit states, care should be taken to ensure that the structural analysis
of the pipe-in-pipe system results in a conservative estimate of forces and moments in each element of the
system.
5.1.2.7 Pipe-in-pipe assemblies generally have a high bending stiffness due to the contribution from both inner
and outer pipes. However, it should be acknowledged in the design that (in an unbonded pipe-in-pipe system) the
bending stiffness of the overall system is not the summation of the individual bending stiffnesses due to the
following:
•
•
A certain degree of relative movement between the pipes is permitted due to the radial gap between
the centralisers and the outer pipe. However, at higher bending loads the system should ‘lock up’, with
the combined stiffness tending towards the sum of the individual stiffnesses of the two pipes.
In reeled systems, the inner and outer pipes are likely to have different curvatures due to residual
curvature effected by the reeling and unreeling process.
5.1.2.8 Depending on the type of analysis performed, a higher or lower bending stiffness may be more onerous.
The most conservative estimate of the pipe-in-pipe system stiffness should be selected unless a more
representative value is otherwise demonstrated. The proportion of load shared between the carrier pipe and the
flowline should also be carefully assessed to ensure conservatism for the analysis under consideration.
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5.1.3
Bulkheads
5.1.3.1 The inner and outer pipes are connected by bulkheads at the extremities of the pipeline (end bulkheads)
and occasionally at intermediate locations along the pipeline (intermediate, or midline, bulkheads). Intermediate
bulkheads may be utilised to segment portions of the pipeline annulus for contingency purposes or to limit the
loading transferred between the inner and outer pipes at the end bulkheads. Regardless of the position of the
bulkhead within the system, it should be assessed against a recognised Pressure Vessel Code, such as ASME
BPVC Section VIII Division 2. The entire bulkhead should be assessed against the Pressure Vessel Code,
including connected parts of the pipeline where stress distribution is affected by the presence of the bulkhead. A
typical code break for an end bulkhead is shown in Figure 5.1 Bulkhead code break, with the parts assessed
against the Pressure Vessel Code coloured orange and parts assessed against the pipeline Code coloured grey.
For parts assessed against the pipeline design Code, care should be taken to ensure that the stresses within
these parts have returned to nominal pipeline stresses and that the stress distribution is unaffected by the
presence of the bulkhead.
Figure 5.1 Bulkhead code break
5.1.4
Centralisers
5.1.4.1 Centralisers, also known as spacers, are utilised at regular intervals in a pipe-in-pipe system to ensure
the inner flowline remains centralised within the carrier pipe. Centralisers typically take the form of two polymer
half-shell rings that are bolted together around the inner flowline. A typical arrangement of a pipe-in-pipe crosssection is presented in Figure 5.2 Pipe-in-pipe cross-section.
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Figure 5.2 Pipe-in-pipe cross-section
5.1.4.2 The main functional requirements of the centraliser are to maintain the position of the inner pipe
(preventing buckling) and to prevent compression of the dry insulation within the annular space between the
pipes, as this can degrade the thermal performance of the system. To fulfil this requirement, the thickness of the
centraliser must be greater than the thickness of the insulation after taking account of the loss of initial centraliser
thickness through abrasion (during insertion of the flowline into the carrier pipe) and creep (long-term thermal
degradation). Figure 5.3 Pipe-in-pipe annulus cross-section presents a typical cross-section through the annular
space between the flowline and the carrier pipe.
Figure 5.3 Pipe-in-pipe annulus cross section
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Chapter 1 – Section 5
5.1.4.3 In a typical pipe-in-pipe construction the inner pipe, with insulation and centralisers installed, is inserted
into the carrier pipe. This necessitates the centralisers to pass over the girth weld root beads of the assembled
carrier pipe stalk and can result in abrasion of the centralisers. The degree of abrasion that occurs is a function of
the length along which the flowline is pushed, the number and size of carrier pipe weld beads to be passed, and
the mass each centraliser is required to support. An abrasion test to determine the amount of centraliser
thickness loss should be performed as part of the project qualification programme.
5.1.4.4 Following centraliser fit-up onto the inner pipe, local creep of the centraliser polymer at the bolting
location can occur, which reduces the bolt tension and subsequently the grip applied by the centraliser to the
inner pipe. Sufficient residual bolt tension is required to maintain the centralisers in their intended positions along
the inner pipe after accounting for bolt relaxation during flowline stalk insertion and pipe-in-pipe installation
(covering reeling, unreeling and pipelay). A bolt relaxation test to determine acceptability of the residual bolt
tension should be considered as part of the project qualification programme.
5.1.4.5 During the process of inserting the flowline into the carrier pipe stalk, the centralisers are required to slip
against the carrier pipe while remaining clamped to the flowline. To ensure this will occur during pipe-in-pipe
fabrication, a slippage test should be considered as part of the project qualification programme to determine the
relevant loads for slippage against either pipe. Often a high-grip coating is applied to the inner surface of the
centraliser to increase the load required for slippage to occur relative to the flowline.
5.1.4.6 Centralisers are installed at a regular spacing, also referred to as the centraliser pitch, along the inner
pipe. While the centraliser pitch may be selected based on the insulation panel size for practicality reasons, it
should be confirmed in the reeling analysis that the pitch is sufficiently low to prevent compression of the
insulation due to deflection of the inner pipe between centralisers as the pipe-in-pipe system is reeled. The
chosen centraliser pitch also influences the load applied to each individual centraliser during the reeling process.
Therefore, the capacity of the centraliser to withstand compressive loads may govern the pitch selection. During
the reeling process the centraliser is exposed to its maximum compressive load as the pipe-in-pipe system is
plastically deformed. A compression test/stress analysis to document that this load is within the capacity of the
centraliser should be considered as part of the project qualification programme.
5.1.4.7 In service, the inner pipe of a pipe-in-pipe system typically operates at a high temperature and
consequently the centraliser can also be exposed to high temperatures in operation. In combination with the
applied operational compressive loads, the elevated temperatures can result in creep of the centraliser over the
design life. A creep test to determine the amount of centraliser thickness reduction should be considered as part
of the project qualification programme.
5.1.4.8 The design and qualification test programme for a centraliser should fully cover the project design loads
and should consider credible potential orientations of the centraliser bolts. This is typically covered by considering
the bolts in the 3–9 and 6–12 o’clock positions shown in Figure 5.4 Centraliser bolt orientations.
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Figure 5.4 Centraliser bolt orientations
5.1.4.9 In summary, a typical centraliser qualification programme would include:
•
•
•
•
•
Compression test/stress analysis – Performed to demonstrate that the maximum load applied to the
centraliser, which occurs during the pipeline reeling process, is within the capacity of the centraliser.
Abrasion test – Performed to determine the thickness loss of the centraliser during the insertion of the
flowline into the carrier pipe.
Creep test – Performed to determine the thickness loss due to creep of the centraliser polymer when
subjected to elevated temperature.
Slippage test – Performed to determine the loading required to make the centraliser slip on the carrier
pipe and the flowline.
Bolt relaxation – Performed to demonstrate that sufficient bolt tension will remain for flowline insertion
and pipe-in-pipe installation despite losses due to local polymer creep.
5.1.4.10 Historical qualification data may be used where applicable and in agreement with the purchaser.
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Chapter 1 – Section 6
Section 6:Bundles
6.1
General
6.1.1
Overview
6.1.1.1 Pipeline bundles permit the simultaneous installation of production, test and service/chemical lines by
fabricating them within one larger carrier pipe. An example generic bundle configuration of two insulated
production lines and three smaller diameter service/chemical lines is presented in Figure 6.1 Generic bundle
configuration. The internal pipes within the bundle are terminated within towheads at each end of the pipeline.
Figure 6.1 Generic bundles configuration
6.1.1.2 The annulus of the carrier pipe is flooded with seawater to enhance on-bottom stability. While the
internal pipelines should have external corrosion coating, the flooding seawater should be treated with oxygen
scavenger/inhibitor sticks to prevent a corrosive environment forming within the bundle. Consideration should be
given in the design to the consequences of failure of an internal pipeline. Pipes conveying oil can pose significant
safety and environmental hazards as the fluid from the failed pipe may exit the bundle at a different location,
potentially within a high-consequence safety or environmental zone. Gas carrying pipes present the same safety
risk and in addition can destabilise the entire bundle if the gas displaces the seawater from within the bundle
annulus.
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Chapter 1 – Section 7
Section 7:Subsea piping modules
7.1
General
7.1.1
Overview
7.1.1.1 The following guidance is applicable for subsea piping modules and is intended to provide general
guidance on the types of assessment to be considered for the design of the pressure containing equipment within
subsea piping modules.
7.1.1.2 Many oil and gas developments include subsea piping modules, such as pipeline end manifolds
(PLEM), pipeline/flowline end terminations (PLET/FLET), SSIV structures, manifold structures, in-line tee
modules and other valve skids. The design of the piping within these structures should be performed in
accordance with an appropriate pipeline design Code, such as PD-8010-2, ASME B31.4 or ASME B31.8.
7.1.1.3 The in-place stress and fatigue analysis of the module piping should include, as a minimum, the below
loadings:
•
•
•
•
•
Environmental loading (wave, current, seismic, etc.);
Tie-in loads;
Operational loads (internal pressure, temperature, slugging);
Snagging and pull-over loads (if applicable to piping);
External pressure.
7.1.1.4 The piping within the modules should be designed to avoid both vortex induced vibration (VIV) and flow
induced vibration (FIV).
7.1.1.5 For deep water developments, consideration should be given to lowering the speed of the module to
prevent VIV fatigue damage accruing during deployment.
7.1.1.6 Stress intensification factors should be used in the stress analysis of module pipework where required.
Guidance on appropriate intensification factors is available in ASME B31.3.
7.1.1.7 The susceptibility of duplex and super-duplex pipework to HISC should be assessed as part of the
design process. Guidance on the assessment of susceptibility to HISC is available in DNV-RP-F112.
7.1.1.8 Settlement of the piping structure should be investigated as part of the design of the structure
foundation, and the impact of this on the tie-in infrastructure should be considered. Furthermore, the possibility of
uneven settlement (such as on very uneven seabeds) should be considered, as this may result in tilting of the
structure imparting rotational loads on the tie-in infrastructure.
7.1.1.9 Guidance on the analysis of anchor flanges for subsea modules is provided in Section 7.1.2 Anchor
flanges.
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7.1.2
Anchor flanges
7.1.2.1 Anchor flanges are a common feature of rigid risers and subsea piping modules, where they function to
transfer loads from the riser/piping to the adjoining structure. The designs of anchor flanges for risers are typically
based on the dimensions of existing standard flanges, while those for subsea modules are often similar to pipein-pipe bulkheads. Two common designs of pipeline anchor flange are presented in Figure 7.1 Common pipeline
anchor flanges.
Figure 7.1 Common pipeline anchor flanges
7.1.2.2 Anchor flanges should be designed in accordance with an appropriate stress analysis Code such as
ASME BPVC VIII Division 2. The margin of safety used for the analysis and design of the anchor flange should
be greater than or equal to the safety factor of the adjoining piping/riser.
Section 8:Out-of-straightness (OOS) assessment
8.1
Introduction and scope
8.1.1
General
8.1.1.1 Significant axial compressive loads can be generated in subsea pipelines due to functional loads such
as internal pressure and elevated temperature. Once a threshold compressive load is reached, instability/global
buckling of the pipeline can occur if there is insufficient external restraint available to resist transverse movement
of the pipeline. Once a pipeline buckles, a significant level of axial expansion may feed into the buckle, resulting
in excessive bending of the pipe and potential rupture of the pipeline due to exceedance of pipe cross-section
limit states.
8.1.1.2 The form the global buckle will take depends on the support conditions around the pipe. Buried pipelines
will generally buckle upwards through the backfill material, or potentially downwards into the underlying soil in
cases where the stiffness of the pipe foundation is lower than the backfill material. Exposed pipelines can
potentially buckle downwards at free-spans, upwards at a feature crest or laterally across the seabed.
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8.1.1.3 Following installation, pipelines are surveyed to document the profile of the pipeline and to ascertain
how this compares to the design case. Out-of-straightness analysis is performed to quantify the propensity for
buckling and identify if any preventative measures are required to avert buckling.
8.1.1.4 This Section of the RP is applicable to the structural design of buried pipelines that may undergo global
buckling in the vertical plane only. Lateral buckling of surface laid pipeline is outside the scope of this Section.
Local buckling of the pipe cross-section and the assessment of this failure mechanism is outside the scope of this
Section.
8.1.1.5 The general process for OOS assessment is described in Table 8.1 OOS assessment overview.
Table 8.1
OOS assessment overview
OOS Assessment
Step
Raw data screening
Data smoothing
Survey data
accuracy
assessment
SRA load factors
Analytical OOS
screening
assessment
(optional)
FEA OOS
assessment
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Description
Subsea Pipeline RP Section
Prior to smoothing, the raw survey data should
first be screened to identify any rogue data points,
gaps or abrupt transitions which would impact on
the data smoothing process.
The purpose of data smoothing is to estimate the
real pipe profile based on the raw survey data.
The output of the data smoothing step should be
a continuous profile which may then be used to
assess the propensity for global buckling.
To determine a suitable safety factor which
should be applied in the OOS buckling
assessment, the degree of smoothing which has
been performed to the raw data should be
quantified. The standard deviation of the raw data
adjustments (to create the smoothed profile) is
determined based on a moving window along the
pipeline.
To ensure a consistent level of safety/reliability is
achieved in the OOS assessment, a structural
reliability assessment (SRA) may be performed.
The SRA approach is used to derive safety
factors which account for project-specific
uncertainties, including the accuracy of the survey
data (which normally contributes significantly to
the required safety factor).
Analytical methods may be used to perform an
initial OOS assessment, based on the smoothed
data profile, to determine the approximate
stresses and download requirements for long
lengths of the pipeline. The results of an
analytical OOS assessment should be verified by
performing a non-linear FEA assessment.
The required download should be determined
using a non-linear FEA assessment of the pipe
profile. The model should incorporate appropriate
safety factors (which are recommended to be
calculated by the SRA approach) to account
primarily for any uncertainty of the pipe geometry
and backfill cover height. Detailed guidance on
how to perform the OOS FEA assessment is
outside the scope of this document.
Section 8.2.3 Initial Screening
Section 8.2.4 Smoothing
Section 8.2.5 Standard deviation
of survey data
Section 8.3 Structural reliability
assessment
Section 8.4.2 Analytical OOS
screening
Section 8.4.4 Finite Element OOS
Analysis
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Chapter 1 – Section 8
8.2
Data smoothing
8.2.1
General
8.2.1.1 The accuracy of out-of-straightness survey data is variable and depends upon multiple factors including
method of survey, environmental conditions, backfill type and proximity of the survey tool to the pipe. The density
of data gathered is also variable and depends upon the survey technique adopted; however, generally a
significant volume of data points is gathered. This inherent variability in the acquired data in terms of axial
spacing and vertical position, on a point-by-point basis, introduces an uncertainty of the actual pipeline position
and global configuration. Therefore, the out-of-straightness data needs to be processed to remove noise and to
make a best estimate of the actual pipe profile which may be used for analysis.
8.2.1.2 During the data acquisition phase, the raw survey data will be subjected to a degree of inherent
smoothing by the methods used to process the data into the KP and ToP listings typically presented. It is
important to ensure that the sample has not been unduly over-smoothed or data points averaged at too large a
spacing, as this loss of fidelity may prevent features from being detected.
8.2.1.3 Many techniques are available to the analyst to remove random noise from the survey dataset.
Simplistic filters such as moving averages have the benefits of being transparent in operation, being relatively
simple to implement and having fast data processing times. However, this type of filter may over-smooth the
data, locally and/or globally, and thus remove real features as well as the survey noise. More complex data filters
may alleviate some of these concerns but are often computationally more expensive and less transparent in
operation.
8.2.1.4 A specific smoothing technique is not recommended, as the ‘best’ technique will vary depending on the
survey dataset, required analysis speed and analyst capability. In selecting a smoothing technique, the analyst
should consider the benefits and limitations of the available techniques. In LR’s experience, multi-pass Gaussian
kernels and modified Savitzky–Golay filters have proved to be competent in processing survey data.
8.2.2
Smoothing routine
8.2.2.1 The key aim of the smoothing routine is to remove as much random noise as possible from the raw
survey dataset while preserving the real data. While it is possible to perform out-of-straightness assessments
analytically, there are limits to the applicability of this method, so ultimately most smoothing routines are used to
prepare the data for FE assessment. It should be noted that assessment in FE may introduce a further level of
smoothing as a result of the way the seabed is modelled (normally using soil springs). Consequently, the target of
the smoothing routine is to achieve a slightly under-smoothed pipeline profile so that the FE smoothing does not
under-represent real profile features.
8.2.3
Initial screening
8.2.3.1 Prior to engaging in any smoothing of the survey dataset, the analyst should first visually examine the
raw survey data. The visual screening is performed so that any rogue data points, gaps or abrupt transitions in
the dataset are identified. Rogue data points are characterised as being data points that are outside the normal
scatter associated with random noise and are clearly identifiable as not being genuine measurement points. An
example of a rogue data point is shown in Figure 8.1 OOS survey data – Rogue data point. It is clear from the
figure that while the highlighted data point is in an area of increased data scatter, it is not part of the ‘real’ dataset
and is fictitious. It should be noted that all other data points within the presented section are considered to be part
of the random data scatter and should be progressed to the smoothing stage.
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Chapter 1 – Section 8
Figure 8.1 OOS survey data – Rogue data point
8.2.3.2 In some cases, particularly for longer pipelines, the pipeline may require several surveys covering
different KP ranges. It should be ensured that there is sufficient overlap at the boundaries of these surveys so
any out-of-straightness features which lie at the survey boundaries are fully captured. Where two distinct surveys
are combined there may be an abrupt vertical transition. This may be due to meteorological conditions resulting
in different water depths at the times of survey and therefore different recorded vertical pipe positions. Similarly,
for internal surveys any difference in datum point may result in different pipe positions being recorded. Abrupt
transitions that can be explained, such as those discussed above, may be rectified in the dataset provided that
sufficient data exists. For example, in the case of two external surveys which have a degree of axial overlap
between them but are out of phase in the vertical plane, one of the datasets may be adjusted vertically so that the
abrupt transition is removed. When performing this procedure, the operation must be applied to the whole dataset
so that features within the dataset are unaffected. Any adjustments of the datasets should be kept to a minimum
and whenever an adjustment is made it should be recorded in the analysis report with appropriate justifications
provided. Sections of the survey which contain abrupt transitions that cannot be explained and sections where
there are gaps in the data should be re-surveyed. An example of an abrupt transition between survey datasets
that has been corrected is shown in Figure 8.2 OOS survey data – Vertical data adjustment.
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Chapter 1 – Section 8
Figure 8.2 OOS survey data - Vertical data adjustment
8.2.4
Smoothing
8.2.4.1 Once all rogue data points are removed and any appropriate adjustments are made, the survey data
may be ‘smoothed’ to derive a continuous pipeline profile. The level of smoothing applied at a particular data
point is typically controlled by adjusting the size of the smoothing window used. The positions of all the data
points located within the smoothing window are then combined to determine the new position of the data point
under consideration. Certain smoothing algorithms will specify a number of data points to be considered rather
than a window size. Care should be taken when using such methods as unless the data points are equally
spaced, the smoothing window size will vary with the data density. Every smoothing algorithm will take a different
approach to how the data points are combined and the degree of influence attached to each data point. This
process of adjusting the position of data points by taking account of their surrounding data points serves to
remove the sharp irregularities from the random survey noise.
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8.2.4.2 Determining the size of the smoothing window can be a subjective process, and ultimately it is left to the
analyst to ensure that an appropriate value is selected. Figure 8.3 OOS data smoothing – Raw data vs several
smoothing windows of same filter illustrates three different smoothed pipe profiles resulting from three different
smoothing windows.
Figure 8.3 OOS data smoothing – Raw data vs several smoothing windows of same filter
8.2.4.3 The smoothing process itself is typically highly iterative, with many window sizes considered until the
most appropriate size is determined. Despite the highly subjective nature of the smoothing process, there are
several techniques that can be utilised to ensure an appropriate level of smoothing is applied.
8.2.4.4 Initially, a low level of smoothing should be performed (the exact size of the bandwidth will depend on
the smoothing algorithm) and the profile should then be tested for acceptance by using the methods outlined
below. If the profile is deemed to be under-smoothed, then the bandwidth factor should be increased and the
process repeated. Once an appropriate profile has been achieved, the smoothing factor should be reduced
slightly to arrive at a slightly under-smoothed profile for FE analysis. In general, an under-smoothed profile will be
conservative as tighter curvatures in the profile will result in higher bending stresses and the pipe will also have
greater propensity for upheaval buckling.
8.2.4.5 As the smoothing factor is progressively increased there are several methods, both visual and
analytical, that can be used to aid the analyst in identifying if the smoothing window is appropriate.
(a) Visual identification – The implementation of smoothing routines results in the adjustment of all data
points to varying degrees. Particular attention must be given to data points located at locally extreme
vertical positions, such as those at peaks and troughs of OOS features. Poorly implemented smoothing
routines or over-smoothing will result in the smoothed pipe position ‘pulling away’ excessively from the
source OOS data and in flattening of the pipe profile. This can be avoided by the use of weighted filters
or multi-pass filters. Once a smoothing bandwidth has been chosen it should be visually verified that at
key feature locations the new profile has not been unduly smoothed, and the features have not been
flattened.
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Chapter 1 – Section 8
(b) Prop identification – Identification of prop-type features can be used to quickly determine if a profile is
under-smoothed. Typically, in under-smoothed profiles, the random noise present in survey data will
manifest as multiple short wavelength features along the entire survey length. Therefore, implementing
a screening check to report the frequency of prop-like features can assist the analyst to identify profile
under-smoothing. Care should be taken as there may be legitimate props in the pipeline profile;
therefore, once wide-ranging small wavelength features have been removed, remaining identified props
should be investigated to confirm if they are genuine. Separately, the pipeline OOS design should be
demonstrated to be tolerant to undetectable prop-type features which are within the statistical bounds of
the scatter in the survey data.
(c) Curvature/stress check – The suitability of the smoothed profile may be tested analytically by
examining the curvature of the profile. Curvature of the smoothed profile may be calculated using
methods such as finite difference or by direct derivative if a polynomial-based smoothing routine is
adopted. The calculated curvatures can be compared to yield curvatures or other limiting values.
Recording of high curvatures would typically indicate that the pipeline profile would fail the final FEA
conformance test and could therefore be smoothed further. Care should be taken when adjusting the
smoothing parameter as a result of this check to ensure that real locations of high curvature are not
over-smoothed.
(d) FEA conformance – A final check of the smoothed profile should be performed in FEA to confirm that
the pipeline conforms to the profile. In principle the pipe should conform perfectly to the profile in FEA
(smoothed profile modelled as a rigid surface on which the pipe is laid). However, some small gaps
between the pipeline and the profile may remain, but these should be small. If large gaps are found, the
profile should be investigated and consideration should be given to additional smoothing of the profile.
8.2.5
Standard deviation of survey data
8.2.5.1 The degree of random noise in the survey data is a key input parameter for a structural reliability
assessment (see Section 8.3 Structural reliability assessment). This is quantified by calculating the standard
deviation of the distances between the raw survey data points and the smoothed profile. Data points which have
been categorised as being rogue/erroneous data points should be excluded from this analysis.
8.2.5.2 Standard deviations are calculated within a ‘window’ centred on each data point. Every data point within
the window is used to calculate the standard deviation. For dense datasets it is acceptable to calculate the
standard deviations at 1 m target intervals rather than at every data point. The scatter of data or adherence of the
smoothed profile to the raw data cloud can vary along a pipeline. Therefore, the selection of ‘window’ size should
be of a meaningful length which can capture changes in the quality of the fit of the smoothed profile for typical
OOS features. The size of the window may vary depending upon the pipeline stiffness and weight. A standard
deviation window of 25 m is recommended unless specific project parameters require otherwise.
8.2.5.3 It should be noted that a low standard deviation is not necessarily a hallmark of good survey data or
smoothing, as excessive under-smoothing will result in a lower standard deviation. Consequently, it is important
to ensure the smoothing routine has been correctly implemented and adhered to.
8.3
Structural reliability assessment
8.3.1
General
8.3.1.1 To ensure that a consistent level of safety/reliability is achieved in the out-of-straightness assessment, a
structural reliability assessment (SRA) may be performed, taking account of the project-specific variability of input
parameters (such as the accuracy of the survey data).
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8.3.1.2 Structural reliability methods may be used to calculate a unified safety factor, which is applied to the
effective axial force, or partial safety factors may be determined to be applied to the effective axial force and the
required soil resistance.
8.3.1.3 It is recommended that unique safety factors are determined for intervals of out-of-straightness feature
heights, considering the variability of input data as a function of the distance along the pipeline. This allows
benefit to be taken of areas with low imperfection heights, low survey standard deviation or decreasing
temperature profile, for example.
8.3.1.4 Detailed guidance on how to perform a structural reliability assessment is planned to be included in a
future revision of this RP.
8.3.2
SRA Load cases
8.3.2.1 The structural reliability assessment for OOS requires evaluation of several load cases, considering the
operational parameters, survey features, consequence of failure and location. The latter two of these
considerations impact the target reliability that the system is required to achieve. Target reliability factors for
global destabilisation failure modes such as OOS are typically taken from ISO 16708 Annex C. It may be
acceptable to consider a lower target reliability for commissioning hydrotest load cases, considering differences
in the consequence of failure. Sections of the pipeline located in high-safety areas will generally require more
onerous target reliabilities.
8.3.2.2 If no significant change in operational parameters or risk profile is anticipated to occur over the design
life, load factors calculated for the start-of-life (SOL) condition may also be used for the end-of-life (EOL)
condition.
8.3.2.3 The pipeline route may be segmented into several sections so that advantage may be taken of sections
with low profile feature heights, low survey standard deviations or reduced operational parameters.
8.3.2.4 For each identified load case, the most onerous operational parameters for that specific section of
pipeline shall be used in the structural reliability assessment. The maximum prop equivalent feature height within
the analysed section shall be identified and used as the upper bound feature height in the assessment. The SRA
analysis should then be repeated to determine the applicable safety factors for selected prop heights between the
undetectable feature height and the maximum prop equivalent imperfection.
8.3.2.5 An assessment shall be performed to determine the blanket cover requirement to prevent buckling at
undetectable features. For this load case, the prop imperfection should be considered to be deterministic with a
magnitude two times the standard deviation from the survey.
8.3.3
Limitations
8.3.3.1 Common structural reliability methods such as Monte Carlo are based on analytical models for definition
of limit states. Consequently, the pipeline is normally idealised as static, with no movement through the soil
column incorporated within the model. This allows the use of classical soil resistance and pipeline driving force
equations but neglects the effects of soil uplift mobilisation distances and stiffness of the soil sub-grade. In reality,
as the pipeline moves through the soil column the curvature will tend to tighten and consequently increase the
driving force. This concern may be somewhat alleviated by increasing the sampled prop height by the soil uplift
mobilisation distance, therefore resulting in a prop shape with tighter curvature. It is recommended to calibrate
the analytical limit state model against equivalent non-linear FEA models where mobilisation of soil resistance is
considered to be significant.
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Chapter 1 – Section 8
8.4
OOS upheaval buckling assessment
8.4.1
General
8.4.1.1 Out-of-straightness assessments are generally performed to determine the uplift requirements along the
pipeline route and to confirm the pipeline remains within its allowable stress limits. It is recommended that OOS
assessment of the smoothed pipeline profile is performed using FEA in order to capture any non-linearities such
as non-linear soil springs. Guidance on how to perform OOS assessments by FEA are in Section 8.4.4 Finite
Element OOS Analysis. As a supplementary screening approach, analytical methods may be utilised to assess
the tendency for upheaval buckling of the smoothed profile. Guidance on the implementation of an analytical
screening approach is provided in Section 8.4.2 Analytical OOS screening.
8.4.2
Analytical OOS screening
8.4.2.1 Out-of-straightness assessments are typically conducted using a non-linear general FEA approach;
however, analytical methods may also be used as a screening method to supplement the FEA in the analysis
process.
8.4.2.2 It is not envisioned that the analytical method is used as a replacement for FE out-of-straightness
analysis, but rather in conjunction with it. By leveraging the advantages of both assessment methods, reasonable
time savings can be achieved. Rapid initial screening of the pipeline out-of-straightness data can be performed
by the analytical method, which can be used as an initial estimate of the required download and to identify any
areas of interest in the OOS data. It should be noted that at present the analytical method is only applicable to
low mobilisation soils with relatively stiff sub-grades.
8.4.2.3 It is recommended that the analytical method is confined to screening checks unless sufficient
verification has been performed to validate the results against FEA.
8.4.2.4 Analytical assessment of pipeline out-of-straightness may be performed using the beam-column theory
equation presented in OTC 6335. As presented below, the required download, w, to maintain the pipeline in its
as-surveyed profile can be calculated at every position along the length using the derivatives of the profile.
Modern computer methods allow the derivatives of the profile obtained from the smoothing process to be defined,
therefore making the equation applicable to any arbitrary feature shape.
𝑤𝑤(𝑥𝑥) = −𝐸𝐸𝐸𝐸
𝑑𝑑2 𝑦𝑦
𝑑𝑑4 𝑦𝑦
−
𝑃𝑃
𝑑𝑑𝑑𝑑 4
𝑑𝑑𝑑𝑑 2
where
𝑤𝑤
=
total required download
=
flexural rigidity
𝑃𝑃
=
effective axial force
𝐸𝐸𝐸𝐸
8.4.2.5 The resistance required to be provided by the soil cover is calculated by subtracting the pipe submerged
weight from the total required download. The soil cover height can therefore be back-calculated from the required
soil resistance.
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8.4.2.6 The load factors derived from the structural reliability analysis should be applied to the effective axial
force used to calculate the required download.
8.4.2.7 It may be convenient to perform analytical stress analysis of the pipeline profile while calculating the
download requirement. The curvature of the pipeline can similarly be found from the derivates of the pipeline
profile and subsequently the bending stress can be calculated as follows.
𝑘𝑘 =
𝑑𝑑2 𝑦𝑦
𝑑𝑑𝑑𝑑 2
3/2
𝑑𝑑𝑑𝑑 2
�1 + � � �
𝑑𝑑𝑑𝑑
σb = 𝑘𝑘𝑘𝑘𝑘𝑘
where
𝑘𝑘
=
curvature
σb
=
bending stress
=
Young’s modulus
𝑧𝑧
=
distance to extreme fibre from elastic neutral axis
𝐸𝐸
8.4.2.8 Inherent in the bending stress calculation is the assumption that the moment–curvature relationship
does not change with curvature, and therefore this methodology is only strictly applicable to stress states below
yield.
8.4.3
Limitations
8.4.3.1 Although there are benefits from using the analytical method, its limitations should be acknowledged.
Predominantly the limitations are due to the linear nature of the assessment, which means that changes in
position due to pipe movement through the soil column are not captured. Therefore, the results from the
analytical method are only applicable when the backfill and sub-grade soil has a low mobilisation distance.
Suitability of the analytical method shall be assessed by comparison of the analytical method with non-linear FEA
assessments for identical initial OOS feature geometries.
8.4.4
Finite Element OOS Analysis
8.4.4.1 The pipeline should be represented in the out-of-straightness analysis by pipe beam elements with a
sufficient length to accurately capture the global pipe behaviour. The elements shall be used in combination with
linear elastic material properties; this is necessary to allow the FEA model to ensure that fully factored axial
forces can be developed.
8.4.4.2 If the pipeline route is subdivided into several sections for analysis, then a sufficient overlap between the
sections should be ensured so that the feed-in to significant imperfections near the model extremities is fully
captured.
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8.4.4.3 Interaction of the pipe with the seabed and the backfill material should be represented by non-linear
springs within the FE model. Separate force–displacement relationships should be developed for the axial,
downwards and upwards directions. It should be noted that the springs in the vertical direction should be
decoupled to ensure that any upwards movement mobilises the overburden regardless of any previous
downwards displacement of the pipe on the downward spring which represents the pipe foundation. In general,
best estimate values of soil resistance should be used in the buckling assessment, as the uncertainty in the soil
resistance should be accounted for in the load factors derived by the SRA approach.
8.4.4.4 Generally, only one load factor may be applied per finite element model; therefore, the model should be
repeated for all load factors required. The load factor calculated from the structural reliability assessment should
be applied to the effective axial force in the out-of-straightness assessment. In practice, this is achieved by
scaling the operational inputs to the effective axial force equation by the calculated load factor, i.e. the operating
pressure, operating temperature and installation temperature.
8.4.4.5 For cases where the ends of the pipeline are unconstrained, the load factor should also be applied in the
effective axial force ramp sections. In these regions the effective axial force is purely a function of the soil axial
resistance; consequently, the resistance should be scaled by the load factor for these locations. It should be
noted this will steepen the gradient of effective axial force build-up and reduce the anchor length.
8.4.5
Acceptance criteria
8.4.5.1 For design against upheaval buckling, the pipeline configuration including the level of available
download is deemed to be acceptable if the upwards movement, considering SRA safety factors, is restrained by
the backfill cover. It should also be checked whether ratcheting is anticipated to occur due to operational cycling
of the pipeline. Ratcheting may occur if the pipeline moves sufficiently upwards during operation that it allows
backfill material to fill the void created beneath the pipe. In the absence of project-specific data, the guidance
provided in OTC 21802 may be followed.
8.4.5.2 In addition to prevention of global buckling, the pipeline shall also be demonstrated to satisfy the
requirements of the primary design Code with respect to cross-sectional capacity. It should be noted that the
stress check may limit the allowable vertical displacement that the pipeline can safely tolerate and therefore
additional backfill beyond that required to mitigate buckling may be necessary.
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Chapter 1 – Section 9
Section 9:Change of use
9.1
General
9.1.1
Overview
9.1.1.1 Pipelines are a highly efficient means of transporting fluids and it may be advantageous to repurpose
them to convey different fluids as technology, industry and societal changes occur.
9.1.2
Pipeline reuse
9.1.2.1 Pipelines designed to convey hydrocarbons may prove beneficial later in transporting other fluids. This
change of use may involve, for example, converting the pipeline to:
•
•
•
Conveying captured CO2 offshore for storage in existing reservoirs;
Providing an export route for green hydrogen generated offshore by renewable power;
Supplying gas lift or water injection to existing wells to economically enable greater oil recovery.
9.1.2.2 While reuse of an existing pipeline asset can be attractive from an economical and environmental
perspective, the pipeline must, however, still be demonstrated to be suitable for its new intended service. This
reassessment should be performed to demonstrate suitability for the anticipated new life in accordance with a
modern design Code specifically appropriate for the new form of use.
9.1.2.3 A risk assessment should be performed to identify any new risks, failure modes and consequences that
could occur under the new intended operational parameters. For example, pipeline reuse to convey fluids such
as hydrogen may introduce new material degradation mechanisms and cracking failure modes that may not have
been fully considered in the original design and therefore a material compatibility study should be performed to
confirm that the pipeline is suitable for the intended fluid.
9.1.2.4 The change of use of the pipeline may also necessitate a revision to the pipeline safety class depending
on the original and intended future service. This may have implications for the pipeline design limit states, such
as pressure containment, collapse, propagation buckling and global buckling, and any adverse effect on these
should be fully investigated.
9.1.2.5 The reanalysis of the pipeline should take account of the fatigue damage accrued in its previous service.
Particular care should be taken where the change of conveyed fluid results in a different safety class, as this may
severely affect the permitted remaining fatigue life.
9.1.2.6 Prior to initiating the change of use, a comprehensive inspection of the pipeline should be performed to
document any degradation that has occurred over its original life and provide a base line for the reassessment.
9.1.2.7 In the case of gas pipelines, the pipe material is specified with sufficient fracture toughness to arrest a
ductile fracture and prevent it from developing into a running fracture which can potentially fracture long lengths
of the pipeline. A ductile fracture is arrested when the fracture propagation speed is less than the speed of the
gas decompression wave, which in turn depends on the properties of the gas being transported by the pipeline.
The decompression wave speed is further sensitive to whether the gas remains in the single-phase or enters the
two-phase region of the P-T curve during the decompression process. Therefore, in the event of a change of fluid
(gas) transported by the pipeline, the implications on susceptibility to running fracture should be investigated.
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