abs64-guide for building and classing-subsea pipeline systems and risers

GUIDE FOR BUILDING AND CLASSING

SUBSEA PIPELINE SYSTEMS AND RISERS

MARCH 2001

American Bureau of ShippingIncorporated by Act of Legislature ofthe State of New York 1862

Copyright 2001American Bureau of ShippingABS Plaza16855 Northchase DriveHouston, TX 77060 USA

ABS GUIDE FOR BUILDING AND CLASSING SUBSEA PIPELINE SYSTEMS AND RISERS 2001 i

Foreword

This Guide applies to Classification of design, construction and installation of offshore pipelines andconnected risers made of metallic materials, as well as the periodic surveys required for maintenanceof classification. Serviceability of pipelines and risers is also addressed, but only to the extent thatproper functioning of the pipe and its components affects safety. This Guide may also be used forCertification or Verification of either design, construction or installation of pipelines and risers. ABSwill Certify or Verify design, construction and installation of offshore pipelines and connected riserswhen requested by the owner or mandated by government regulations to verify compliance with thisGuide, a set of specific requirements, national standards or other applicable industry standards. IfABS’s Certification or Verification is in accordance with this Guide and covers design, constructionand installation, then the pipeline or riser is also eligible for ABS Classification.

This Guide has been written for worldwide application, and as such, the satisfaction of individualrequirements may require comprehensive data, analyses and plans to demonstrate adequacy. Thisespecially applies for pipelines and risers located in frontier areas, such as those characterized byrelatively great water depth or areas with little or no previous operating experience. Conversely, manyprovisions of this Guide often can be satisfied merely on a comparative basis of local conditions orpast successful practices. The Bureau acknowledges that a wide latitude exists as to the extent andtype of documentation which is required for submission to satisfy this Guide. It is not the intention ofthis Guide to impose requirements or practices in addition to those that have previously provensatisfactory in similar situations.

Where available, design requirements in this Guide have been posed in terms of existingmethodologies and their attendant safety factors, load factors or permissible stresses that are deemedto provide an adequate level of safety. Primarily, the Bureau's use of such methods and limits in thisGuide reflects what is considered to be the current state of practice in offshore pipeline and riserdesign. At the same time, it is acknowledged that new methods of design, construction and installationare constantly evolving. In recognition of these facts, the Guide specifically allows for suchinnovations and the appendices are intended to reflect this. The application of this Guide by theBureau will not seek to inhibit the use of any technological approach that can be shown to produce anacceptable level of safety.

This ABS Guide supersedes the ABS Guide for Building and Classing Undersea Pipeline Systemsand Risers (1991) and is effective 1 March 2001

ABS GUIDE FOR BUILDING AND CLASSING SUBSEA PIPELINE SYSTEMS AND RISERS 2001 iii

GUIDE FOR BUILDING AND CLASSING

SUBSEA PIPELINE SYSTEMS AND RISERS

CONTENTSCHAPTER 1 Scope and Conditions of Classification .................. 1

Section 1 Applicability........................................................ 3

Section 2 Suspension and Cancellation of Class .............. 9

Section 3 Classification Symbols and Notations ............. 13

Section 4 Rules for Classification .................................... 15

Section 5 Other Regulations............................................ 29

Section 6 IACS Audit ....................................................... 21

Section 7 Documents to be Submitted ............................ 23

Section 8 Conditions for Surveys After Construction....... 31

Section 9 Fees................................................................. 41

Section 10 Disagreement .................................................. 43

Section 11 Limitation of Liability ........................................ 45

Section 12 Definitions ........................................................ 47

CHAPTER 2 Materials and Welding ............................................ 51

Section 1 Metallic Pipe .................................................... 53

Section 2 Piping Components and Pipe Coating............. 59

Section 3 Welding of Pipes and Piping Components ...... 65

Section 4 Corrosion Control............................................. 67

CHAPTER 3 Design...................................................................... 71

Section 1 Design Loads................................................... 73

Section 2 Geotechnical Conditions.................................. 77

Section 3 Environmental Effects...................................... 79

Section 4 Strength Criteria............................................... 89

Section 5 Pipeline Rectification and InterventionDesign.............................................................. 97

Section 6 Routing, Installation, Construction andTesting ........................................................... 105

Section 7 Special Considerations for Design of MetallicRisers............................................................. 113

Section 8 Special Considerations for Pipe in PipeDesign............................................................ 123

Section 9 Special Considerations for Pipeline BundleDesign............................................................ 125

iv ABS GUIDE FOR BUILDING AND CLASSING SUBSEA PIPELINE SYSTEMS AND RISERS 2001

CHAPTER 4 Inspection and Maintenance.................................131

Section 1 Inspection, Maintenance and Repair ............. 133

Section 2 extension of Use ............................................ 139

APPENDIX 1 Limit State Design Criteria ....................................143

Section 1 Limit State Design Principles ......................... 145

Section 2 Classes for Containment. Location, MaterialQuality and Safety ......................................... 147

Section 3 Limit State for Bursting .................................. 153

Section 4 Limit State for Local Buckling ........................ 155

Section 5 Limit State for Fracture of Girth WeldCrack-like Defects.......................................... 161

Section 6 Limit State for Fatigue.................................... 167

Section 7 Limit State for Ratcheting/Out-of-roundness ...................................................... 171

Section 8 Finite Element Analysis of Local Strength ..... 173

APPENDIX 2 Structural Reliability Analysis ..............................177

APPENDIX 3 Risk Management ..................................................183

APPENDIX 4 Assessment of Corrosion, Dent and Crack-likeDefects ...................................................................189

Section 1 Corrosion Defect Assessment ....................... 191

Section 2 Maximum Allowable Operating Pressure forDented Pipes ................................................. 201

APPENDIX 5 References by Organization .................................205

ABS GUIDE FOR BUILDING AND CLASSING SUBSEA PIPELINE SYSTEMS AND RISERS 2001 1

C H A P T E R 1 Scope and Conditions ofClassification

CONTENTSSECTION 1 Applicability............................................................... 3

1 Process .................................................................... 5

3 Certificates and Reports........................................... 6

5 Representations as to Classification........................ 6

7 Scope of Classification............................................. 6

SECTION 2 Suspension and Cancellation of Class.................... 9

1 Termination of Classification .................................. 11

3 Notice of Surveys ................................................... 11

5 Special Notations ................................................... 11

7 Suspension of Class .............................................. 11

9 Lifting of Suspension.............................................. 12

11 Cancellation of Class ............................................. 12

SECTION 3 Classification Symbols and Notations .................. 13

1 Pipelines or Risers Built under Survey................... 13

3 Pipelines and Risers not Built under Survey.......... 13

5 Classification Data.................................................. 13

SECTION 4 Rules for Classification .......................................... 15

1 Application.............................................................. 17

3 Alternatives............................................................. 17

5 Novel Features ....................................................... 17

7 Effective Date of Change in Requirement.............. 17

SECTION 5 Other Regulations................................................... 19

1 International and Other Regulations ...................... 19

3 Governmental Regulations..................................... 19

SECTION 6 IACS Audit ............................................................... 21

SECTION 7 Documents to be Submitted................................... 23

1 General................................................................... 25

3 Plans and Specifications ........................................ 25

5 Information Memorandum ...................................... 25

7 Site-specific Conditions.......................................... 26

9 Material Specifications ........................................... 26

11 Design Data and Calculations................................ 27

2 ABS GUIDE FOR BUILDING AND CLASSING SUBSEA PIPELINE SYSTEMS AND RISERS 2001

13 Installation Manual ................................................. 28

15 Pressure Test Report ............................................. 29

17 Operations Manual ................................................. 29

19 Maintenance Manual .............................................. 29

21 As-built Documents ................................................ 29

SECTION 8 Survey, Inspection and Testing..............................31

1 General................................................................... 33

3 Inspection and Testing in Fabrication Phase ......... 34

5 Inspection and Testing during Installation.............. 37

7 Conditions for Surveys after Construction.............. 38

8 In-service Inspection and Survey........................... 39

9 Inspection for Extension of Use ............................. 39

SECTION 9 Fees ..........................................................................41

SECTION 10 Disagreement...........................................................43

1 Guide...................................................................... 43

3 Surveyors ............................................................... 43

SECTION 11 Limitation of Liability...............................................45

SECTION 12 Definitions................................................................47

1 Classification .......................................................... 49

3 Constructor or Contractor....................................... 49

5 Extension of Use .................................................... 49

7 Maximum Allowable Operating Pressure............... 49

9 Offshore.................................................................. 49

11 Operator ................................................................. 49

13 Owner..................................................................... 49

15 Pipeline................................................................... 50

17 Pipeline System...................................................... 50

19 Recurrence Period or Return Period...................... 50

21 Riser ....................................................................... 50



S E C T I O N 1 Applicability

CONTENTS1 Process .................................................................................... 5

3 Certificates and Reports ......................................................... 6

5 Representations as to Classification ..................................... 6

7 Scope of Classification ........................................................... 6



S E C T I O N 1 Applicability

The intention of this Guide is to serve as a technical documentation for design, fabrication, installationand maintenance of offshore production, transfer and export pipelines and connected risers made ofmetallic materials. The principal objectives are to specify the minimum requirements for Classing,Continuance of Classing, Certification and Verification by the Bureau.

In addition to the requirements of this Guide, the design of a marine system requires consideration ofall relevant factors related to its functional requirements and long term integrity, such as:

Compliance with local Laws, Acts and Regulations;

Functional requirements;

Physical site information;

Operational requirements.

1 ProcessThe classification process consists of:

a) Development of Rules, Guides, standards and other criteria for the design, construction,installation and maintenance of offshore pipelines and metallic risers,

b) Review of the design and survey during and after construction to verify compliance with suchRules and Guides, standards and other criteria,

c) Assignment and registration of class when such compliance has been verified, and

d) Issuance of a renewable Classification Certificate.

The Rules, Guides and standards are developed by Bureau staff and passed upon by committees madeup of naval architects, marine engineers, shipbuilders, engine builders, steel makers and by othertechnical, operating and scientific personnel associated with the worldwide maritime and offshoreindustries. Theoretical research and development, established engineering disciplines, as well assatisfactory service experience are utilized in their development and promulgation. The Bureau and itscommittees can act only upon such theoretical and practical considerations in developing Rules,Guides and standards.

Chapter 1 Scope and Condition of ClassificationSection 1 Applicability 1-1


3 Certificates and Reports

3.1

Plan review and surveys during and after construction are conducted by the Bureau to verify to itselfand its committees that the pipeline, riser, attachments, item of material and other elements thereof arein compliance with the Rules, Guides, standards or other criteria of the Bureau and to the satisfactionof the attending surveyor. All reports and certificates are issued solely for the use of the Bureau, itscommittees, its clients and other authorized entities.

3.3

The Bureau will release certain information to the pipeline and riser underwriters for underwritingpurposes. Such information includes text of overdue conditions of classification, survey due dates andcertificate expiration dates. The Owner will be advised of any request and/or release of information.In the case of overdue conditions of classification, the Owner will be given the opportunity to verifythe accuracy of the information prior to release.

5 Representations as to ClassificationClassification is a representation by the Bureau as to the structural and mechanical fitness for aparticular use or service in accordance with its Rules, Guides and standards. The Rules, Guides andstandards of the American Bureau of Shipping are not meant as a substitute for independentjudgement of professional designers, naval architects, marine engineers, owners, operators, mastersand crew nor as a substitute for the quality control procedures of ship, platform, pipeline and riserconstructors, engine builders, steel makers, suppliers, manufacturers and sellers of marine vessels andstructures, materials, machinery or equipment. The Bureau, being a technical society, can only actthrough Surveyors or others who are believed by it to be skilled and competent.

The Bureau represents solely to the Owner of the pipeline and riser or client of the Bureau that whenassigning class it will use due diligence in the development of Rules, Guides and standards, and inusing normally applied testing standards, procedures and techniques as called for by the Rules, Guidesand standards or other criteria of the Bureau for the purpose of assigning and maintaining class. TheBureau further represents to the Owner of the pipeline and riser or other client of the Bureau that itscertificates and reports evidence compliance only with one or more of the Rules, Guides andstandards or other criteria of the Bureau in accordance with the terms of such certificate or report.Under no circumstances are these representations to be deemed to relate to any third party.

The user of this document is responsible for ensuring compliance with all applicable laws, regulationsand other governmental directives and orders related to a vessel, its machinery and equipment, or theiroperation. Nothing contained in any Rule, Guide, standard, certificate or report issued by the Bureaushall be deemed to relieve any other entity of its duty or responsibility to comply with all applicablelaws, including those related to the environment.

7 Scope of Classification

Nothing contained in any certificate or report is to be deemed to relieve any designer, builder, Owner,manufacturer, seller, supplier, repairer, operator, other entity or person of any warranty express orimplied. Any certificate or report evidences compliance only with one or more of the Rules, Guides,standards or other criteria of the American Bureau of Shipping and is issued solely for the use of theBureau, its committees, its clients or other authorized entities. Nothing contained in any certificate,report, plan or document review or approval is to be deemed to be in any way a representation orstatement beyond those contained in 1-1/5. The validity, applicability and interpretation of any

Chapter 1 Scope and Condition of ClassificationSection 1 Applicability 1-1


certificate, report, plan or document review or approval are governed by the Rules, Guides andstandards of the American Bureau of Shipping who shall remain the sole judge thereof. The Bureau isnot responsible for the consequences arising from the use by other parties of the Rules, Guides,standards or other criteria of the American Bureau of Shipping, without review, plan approval andsurvey by the Bureau.

The term “approved” shall be interpreted to mean that the plans, reports or documents have beenreviewed for compliance with one or more of the Rules, Guides, standards or other criteria of theBureau.

This Guide is published on the understanding that responsibility for operation, reasonable handlingand loading, as well as avoidance of distributions of loads which are likely to set up abnormallysevere stresses in pipelines or risers does not rest upon the Committee.



S E C T I O N 2 Suspension and Cancellation ofClass

CONTENTS1 Termination of Classification................................................ 11

3 Notice of Surveys .................................................................. 11

5 Special Notations .................................................................. 11

7 Suspension of Class ............................................................. 11

9 Lifting of Suspension............................................................ 12

11 Cancellation of Class ............................................................ 12



S E C T I O N 2 Suspension and Cancellation ofClass

1 Termination of ClassificationThe continuance of the Classification of any pipeline or riser is conditional upon the Guiderequirements for periodical survey, damage survey and other surveys being duly carried out. TheCommittee reserves the right to reconsider, withhold, suspend, or cancel the class of any pipeline orriser for noncompliance with the agreed Rules and Guides, for defects reported by the Surveyorswhich have not been rectified in accordance with their recommendations, or for nonpayment of feeswhich are due on account of Classification, Statutory and other Surveys. Suspension or cancellation ofclass may take effect immediately or after a specified period of time.

3 Notice of SurveysIt is the responsibility of the Owner to ensure that all surveys necessary for the maintenance of classare carried out at the proper time. The Bureau will notify an Owner of upcoming surveys andoutstanding recommendations. This may be done by means of a letter, a quarterly status or othercommunication. The non-receipt of such notice, however, does not absolve the Owner from hisresponsibility to comply with survey requirements for maintenance of class.

5 Special NotationsIf the survey requirements related to maintenance of special notations are not carried out as required,the suspension or cancellation may be limited to those notations only.

7 Suspension of Class

7.1

Class will be suspended and the Certificate of Classification will become invalid, from the date of anyuse, operation, loading condition or other application of any pipeline or riser for which it has not beenapproved and which affects or may affect classification or the structural integrity, quality or fitness fora particular use or service.

Chapter 1 Scope and Condition of ClassificationSection 2 Suspension and Cancellation of Class 1-2


7.3

Class will be suspended and the Certificate of Classification will become invalid in any of thefollowing circumstances:

i) If recommendations issued by the Surveyor are not carried out by their due dates and noextension has been granted;

ii) If the periodical surveys required for maintenance of class, are not carried out by the due dateand no Rule allowed extension has been granted;

iii) If any damage, failure, deterioration, or repair has not been completed as recommended.

7.5

Class may be suspended, in which case the Certificate of Classification will become invalid, ifproposed repairs as referred to in 1-8/7.1 on “Damage, Failure and Repair” have not been submitted tothe Bureau and agreed upon prior to commencement.

9 Lifting of Suspension

9.1

Class will be reinstated after suspension for overdue surveys, upon satisfactory completion of theoverdue surveys. Such surveys will be credited as of the original due date.

9.3

Class will be reinstated after suspension for overdue recommendations, upon satisfactory completionof the overdue recommendation.

9.5

Class will be reinstated after suspension for overdue continuous survey items, upon satisfactorycompletion of the overdue items.

11 Cancellation of Class

11.1

If the circumstances leading to suspension of class are not corrected within the time specified, thepipeline or riser’s class will be canceled.

11.3

A pipeline or riser’s class is canceled immediately when a pipeline or riser resumes operation withouthaving completed recommendations which were required to be dealt with before resuming operations.



S E C T I O N 3 Classification Symbols andNotations

1 Pipelines or Risers Built under SurveyPipelines and risers which have been built to the satisfaction of the Surveyors of the Bureau to the fullrequirements of this Guide or to its equivalent, where approved by the Committee, will be classed anddistinguished in the Record by:

ÀÀÀÀ A1 Offshore Installation – Offshore Pipelines and Risers

3 Pipelines and Risers not Built under SurveyPipelines and risers which have not been built under survey of the Bureau, but which are submittedfor classification, will be subjected to a special classification survey. Where found satisfactory, andthereafter approved by the Committee, they will be classed and distinguished in the Record in themanner as described in 1-3/1, but the mark ÀÀÀÀ signifying survey during construction will be omitted.

5 Classification Data

Data on pipeline or risers will be published in the Record as to the latitude and longitude of itslocation, type, dimensions and depth of water at the site.



S E C T I O N 4 Rules for Classification

CONTENTS1 Application............................................................................. 17

3 Alternatives............................................................................ 17

5 Novel Features....................................................................... 17

7 Effective Date of Change in Requirement............................ 17

7.1 Effective Date ......................................................................... 17

7.3 Implementation of Rule Changes........................................... 18



S E C T I O N 4 Rules for Classification

1 Application

These requirements are applicable to those features that are permanent in nature and can be verifiedby plan review, calculation, physical survey or other appropriate means. Any statement in the Guideregarding other features is to be considered as guidance to the designer, builder, owner, et al.

3 AlternativesThe committee is at all times ready to consider alternative arrangements and designs which can beshown, through either satisfactory service experience or a systematic analysis based on soundengineering principles, to meet the overall safety, serviceability and strength standards of the Rulesand Guides.

The committee will consider special arrangements or design for details of pipelines and risers whichcan be shown to comply with standards recognized in the country in which the pipeline or riser isregistered or built, provided these are not less effective.

5 Novel FeaturesPipelines and risers which contain novel features of design to which the provisions of this Guide arenot directly applicable may be classed, when approved by the Committee, on the basis that this Guide,insofar as applicable, has been complied with and that special consideration has been given to thenovel features based on the best information available at that time.

7 Effective Date of Change in Requirement

7.1 Effective Date

This Guide and subsequent changes to this Guide are to become effective on the date specified by theBureau. In general, the effective date is not less than six months from the date on which the Guide ispublished and released for its use. However, the Bureau may bring into force the Guide or individualchanges before that date if necessary or appropriate.

Chapter 1 Scope and Condition of ClassificationSection 4 Rules for Classification 1-4


7.3 Implementation of Rule Changes

In general, until the effective date, plan approval for designs will follow prior practice, unless reviewunder the latest Guide is specifically requested by the party signatory to the application forclassification. If one or more systems are to be constructed from plans previously approved, noretroactive application of the subsequent Rule changes will be required, except as may be necessary orappropriate for all contemplated construction.



S E C T I O N 5 Other Regulations

1 International and Other Regulations

While this Guide covers the requirements for the classification of offshore pipelines and risers, theattention of Owners, designers, and builders is directed to the regulations of international,governmental and other authorities dealing with those requirements in addition to or over and abovethe classification requirements.

Where authorized by the Administration of a country signatory thereto and upon request of theOwners of a classed pipeline or riser or one intended to be classed, the Bureau will survey forcompliance with the provision of International and Governmental Conventions and Codes, asapplicable.

3 Governmental RegulationsWhere authorized by a government agency and upon request of the Owners of a new or existingoffshore pipeline or riser, the Bureau will survey and certify a classed system or one intended to beclassed for compliance with particular regulations of that government on their behalf.



S E C T I O N 6 IACS Audit

The International Association of Classification Societies (IACS) conducts audits of processesfollowed by all its member societies to assess the degree of compliance with the IACS Quality SystemCertification Scheme requirements. For this purpose, auditors for IACS may accompany ABSpersonnel at any stage of the classification or statutory work, which may necessitate the auditorshaving access to the fixed or floating installation, or access to the premises of the manufacturer orbuilder.

In such instances, prior authorization for the auditor’s access will be sought by the local ABS office.



S E C T I O N 7 Documents to be Submitted

CONTENTS1 General................................................................................... 25

3 Plans and Specifications ...................................................... 25

5 Information Memorandum .................................................... 25

7 Site-specific Conditions........................................................ 26

9 Material Specifications.......................................................... 26

11 Design Data and Calculations .............................................. 27

11.1 Structural Strength and On-bottom Stability Analysis ............ 27

11.3 Installation Analysis................................................................ 27

11.5 Safety Devices........................................................................ 27

13 Installation Manual ................................................................ 28

15 Pressure Test Report ............................................................ 29

17 Operations Manual ................................................................ 29

19 Maintenance Manual ............................................................. 29

21 As-built Documents............................................................... 29



S E C T I O N 7 Documents to be Submitted

1 General

For classing pipelines and risers according to this Guide, the documentation that is to be submitted tothe Bureau is to include reports, calculations, drawings and other documentation necessary todemonstrate the adequacy of the design of the pipelines and risers. Specifically, requireddocumentation is to include the items listed in this Chapter.

3 Plans and SpecificationsPlans and specifications depicting or describing the arrangements and details of the major items ofpipelines and risers are to be submitted for review or approval in a timely manner. These include:

Site plan indicating bathymetric features along the proposed route, the location ofobstructions to be removed, the location of permanent man-made structures, the portions ofthe pipe to be buried and other important features related to the characteristics of the sea floor;

Structural plans and specifications for pipelines and risers, their supports and coating;

Schedules of non-destructive testing and quality control procedures;

Flow diagram indicating temperature and pressure profiles;

Specifications and plans for instrumentation and control systems and safety devices.

When requested by the Owner, the Owner and the Bureau may jointly establish a schedule forinformation submittal and plan approval. This schedule, to which the Bureau will adhere as far asreasonably possible, is to reflect the fabrication and construction schedule and the complexity of thepipeline and riser systems as they affect the time required for review of the submitted data.

5 Information MemorandumAn information memorandum on pipelines and risers is to be prepared and submitted to the Bureau.The Bureau will review the contents of the memorandum to establish consistency with other datasubmitted for the purpose of obtaining classification or certification.

An information memorandum is to contain, as appropriate to the pipelines and risers, the following:

A site plan indicating the general features at the site, and the field location of the pipelinesand risers;

Chapter 1 Scope and Condition of ClassificationSection 7 Documents to be Submitted 1-7


Environmental design criteria, including the recurrence interval used to assess environmentalphenomena;

Plans showing the general arrangement of the pipelines and risers;

Description of the safety and protective systems provided;

Listing of governmental authorities having authority over the pipelines and risers;

Brief description of any monitoring proposed for use on the pipelines and risers;

Description of manufacturing, transportation and installation procedures.

7 Site-specific Conditions

An environmental condition report is to be submitted describing anticipated environmental conditionsduring pipe laying, as well as environmental conditions associated with normal operating conditionsand design environmental condition. Items to be assessed are to include, as appropriate, wind, waves,current, temperature, tide, marine growth, chemical components of air and water, ice conditions,earthquakes and other pertinent phenomena.

A route investigation report is to be submitted addressing, with respect to the proposed route of thepipeline or riser system, the topics of seafloor topography and geotechnical properties. In thebathymetric survey, the width of the survey along the proposed pipeline or riser route is to be basedon consideration of the expected variation in the final route in comparison with its planned position,and the accuracy of positioning devices used on the vessels employed in the survey and in the pipelaying operation. The survey is to identify, in addition to bottom slopes, the presence of any rocks orother obstructions that might require removal, gullies, ledges, unstable slopes, and permanentobstructions, such as existing man-made structures. The geotechnical properties of the soil are to beestablished to determine the adequacy of its bearing capacity and stability along the route. Themethods of determining the necessary properties are to include a suitable combination of in-situtesting, seismic survey, and boring and sampling techniques. As appropriate, soil testing proceduresare to adequately assess sea floor instability, scour or erosion, and the possibility that soil propertiesmay be altered due to the presence of the pipe, including reductions in soil strength induced by cyclicsoil loading or liquefaction. The feasibility of performing various operations relative to the burial andcovering of the pipe is to be assessed with respect to the established soil properties.

Where appropriate, data established for a previous installation in the vicinity of the pipeline or riserproposed for classification may be utilized, if acceptable to the Bureau.

9 Material Specifications

Documentation for all materials of the major components of pipelines and risers is to indicate that thematerials satisfy the requirements of the pertinent specification.

For linepipes, specifications are to identify the standard with which the product is in completecompliance, the size and weight designations, material grade and class, process of manufacture, heatnumber, and joint number. Where applicable, procedures for storage and transportation of thelinepipes from the fabrication and coating yards to the offshore destination are to be given.

Material tests, if required, are to be performed to the satisfaction of the Bureau.



11 Design Data and CalculationsInformation is to be submitted for the pipelines and risers that describe the methods of analysis anddesign that were employed in establishing the design. The estimated design life of the pipelines andrisers is to be stated. Where model testing is used as the basis for a design, the applicability of the testresults will depend on the demonstration of the adequacy of the methods employed, includingenumeration of possible sources of error, limits of applicability, and methods of extrapolation to fullscale data. It is preferable that the procedures be reviewed and agreed upon before model testing isperformed.

Calculations are to be submitted to demonstrate the adequacy of the proposed design and are to bepresented in a logical and well-referenced fashion employing a consistent system of units. Wheresuitable, at least the following calculations are to be performed:

11.1 Structural Strength and On-bottom Stability Analysis

Calculations are to be performed to demonstrate that, with respect to the established loads and otherinfluences, the pipelines and risers, support structures and surrounding soil possess sufficient strengthand on-bottom stability with regard to failure due to the following:

Excessive stresses and deflections;

Fracture;

Fatigue;

Buckling;

Collapse;

Foundation movements.

Additional calculations may be required to demonstrate the adequacy of the proposed design. Suchcalculations are to include those performed for unusual conditions and arrangements, as well as forthe corrosion protection system.

11.3 Installation Analysis

With regard to the installation procedures, calculations and trenching analysis are to be submitted forreview. These calculations are to demonstrate that the anticipated loading from the selectedinstallation procedures does not jeopardize the strength and integrity of the pipelines and risers andtheir foundations.

11.5 Safety Devices

An analysis of the pipeline safety system is to be submitted to demonstrate compliance with API RP14G. As a recommended minimum, the following safety devices are to be part of the pipelines andrisers:

For departing pipelines and risers a high-low pressure sensor is required on the floater orplatform to shut down the wells, and a check valve is required to avoid backflow;

For incoming pipelines and risers an automatic shutdown valve are to be connected to thefloater or platform’s emergency shutdown system, and a check valve is required to avoidbackflow;

For bi-directional pipelines and risers a high-low pressure sensor is required on the floater orplatform to shut down the wells and an automatic shutdown valve is to be connected to thefloater or platform’s emergency shutdown system.



Shortly after the pipelines and risers are installed, all safety systems are to be checked in order toverify that each device has been properly installed and calibrated and is operational and performing asprescribed.

In the post-installation phase, the safety devices are to be tested at specified regular intervals andperiodically operated so that they don’t become fixed by remaining in the same position for extendedperiods of time.

13 Installation ManualA manual is to be submitted describing procedures to be employed during the installation of pipelinesand risers, and is as a minimum to include:

List of the tolerable limits of the environmental conditions under which pipe laying mayproceed;

Procedures to be followed should abandonment and retrieval be necessary;

Repair procedures to be followed should any component of pipelines or risers be damagedduring installation;

Contingency plan.

An installation manual is to be prepared to demonstrate that the methods and equipment used by thecontractor meet the specified requirements. As a minimum, the qualification of the installation manualis to include procedures related to:

Quality assurance plan and procedures;

Welding procedures and standards;

Welder qualification;

Non-destructive testing procedures;

Repair procedures for field joints, internal and external coating repair, as well as repair ofweld defects, including precautions to be taken during repairs to prevent overstressing therepair joints;

Qualification of pipe-lay facilities, such as tensioner and winch;

Start and finish procedure;

Laying and tensioning procedures;

Abandonment and retrieval procedures;

Subsea tie-in procedures;

Intervention procedures for crossing design, specification and construction, bagging,permanent and temporary support design, specification and construction, etc.;

Trenching procedures;

Burying procedures;

Field joint coating & testing procedures;

Drying procedures;

System Pressure Test procedures and acceptance criteria.

Full details of the lay vessel, including all cranes, abandonment and recovery winches, stingercapacities and angles, welding and non-destructive testing gear, firing line layout and capacity andvessel motion data are to be provided together with general arrangement drawings showing plans,



elevations, and diagrams of the pipeline assembly, welding, non-destructive testing, joint coating, andlay operations. Full details of any trenching and burying equipment is to be provided.

15 Pressure Test Report

A report including procedures for and records of the testing of each pipeline-riser system is to besubmitted. The test records are as a minimum to include an accurate description of the facility beingtested, the pressure gauge readings, the recording gauge charts, the dead weight pressure data, and thereasons for and disposition of any failures during a test. A profile of the pipeline that shows theelevation and test sites over the entire length of the test section is to be included. Records of pressuretests are also to contain the names of the owner and the test contractor, the date, time and testduration, the test medium and its temperature, the weather conditions and sea water and airtemperatures during the test period. Plans for the disposal of test medium together with dischargepermits may be required submitted to the Bureau.

17 Operations ManualAn operations manual is to be prepared to provide a detailed description of the operating proceduresto be followed for expected conditions. The operations manual is to include procedures to be followedduring start-up, operations, shutdown conditions, and anticipated emergency conditions. This manualis to be submitted to the Bureau for record and file.

19 Maintenance ManualA maintenance manual providing detailed procedures for how to ensure the continued operatingsuitability of the pipeline and riser system is to be submitted to the Bureau for approval.

The manual is, as a minimum, to include provisions for the performance of the following items:

Visually inspection of non-buried parts of pipelines and risers to verify that no damages haveoccurred to the systems, and that the systems are not being corroded. Particular attention is tobe paid to corrosion in the splash zone of risers;

Evaluation of the cathodic protection system performance by potential measurements;

Detection of dents and buckles by caliper pigging;

Inspection and testing of safety and control devices.

Additionally, the Bureau may require gauging of pipe thickness, should it be ascertained that pipelinesand risers are undergoing erosion or corrosion.

Complete records of inspections, maintenance and repairs of pipelines and risers are to be providedfor the Bureau.

21 As-built Documents

The results of surveys and inspections of the pipelines and risers are to be given in a report which, as aminimum, is to include the following details:

For pipelines, plot of the final pipeline position, superimposed on the proposed routeincluding pipeline spans and crossings;

Description and location of any major damage to the pipelines and risers alongsideinformation regarding how such damage was repaired;



Description of the effectiveness of burial operations (if applicable for pipelines);

The result of the inspections of the riser tie-in to ensure compliance with all plans andspecifications.

As appropriate, results of additional inspections, which may include those for the proper operation ofcorrosion control systems, buckle detection by caliper pig or other suitable means and the testing ofalarms, instrumentation and safety and emergency shutdown systems, are to be included.



S E C T I O N 8 Survey, Inspection and Testing


1.1 Scope ..................................................................................... 33

1.3 Quality Control and Assurance Program................................ 33

1.5 Access and Notification .......................................................... 34

1.7 Identification of Materials........................................................ 34

3 Inspection and Testing in Fabrication Phase ...................... 34

3.1 Material Quality....................................................................... 34

3.3 Manufacturing Procedure Specification and Qualification ..... 34

3.5 Welder Qualification and Records.......................................... 35

3.7 Pre-Welding Inspection .......................................................... 35

3.9 Welding Procedure Specifications and Qualifications............ 35

3.11 Weld Inspection...................................................................... 35

3.13 Tolerances and Alignments.................................................... 36

3.15 Corrosion Control Systems .................................................... 36

3.17 Concrete Weight Coatings ..................................................... 36

3.19 Non-destructive Testing ......................................................... 36

3.21 Fabrication Records ............................................................... 36

5 Inspection and Testing during Installation .......................... 37

5.1 Specifications and Drawings for Installation........................... 37

5.3 Installation Manual ................................................................. 37

5.5 Inspection and Survey During Pipe laying ............................. 37

5.7 Final Inspection and Pressure Testing................................... 37

5.9 Inspection for Special Cases.................................................. 38

5.11 Notification.............................................................................. 38

7 Conditions for Surveys after Construction.......................... 38

7.1 Damage, Failure and Repair .................................................. 38

7.3 Notification and Availability for Survey ................................... 39

9 In-service Inspection and Survey......................................... 39

11 Inspection for Extension of Use ........................................... 39



S E C T I O N 8 Survey, Inspection and Testing

1 General

1.1 Scope

This section pertains to inspection and survey of pipelines and risers at different phases including:

Fabrication;

Installation:

Testing after installation.

The phases of fabrication and construction covered by this section include pipe and coatingmanufacture, fabrication, assembly, and linepipe pressure test. The phases of installation include routesurvey of the pipelines and risers, preparation, transportation, field installation, construction, systempressure test and survey of the as-built installation. The post-installation phase includes survey forcontinuance of classification accounting for damage, failure and repair.

1.3 Quality Control and Assurance Program

A quality control and assurance program compatible with the type, size and intended functions ofpipelines and risers is to be developed and submitted to the Bureau for review. The Bureau willreview, approve and, as necessary, request modification of this program. The Contractor is to workwith the Bureau to establish the required hold points on the quality control program to form the basisfor all future inspections at the fabrication yard and surveys of the pipeline or riser. As a minimum,the items enumerated in the various applicable subsections below are to be covered by the qualitycontrol program. If required, surveyors may be assigned to monitor the fabrication of pipelines andrisers and assure that competent personnel are carrying out all tests and inspections specified in thequality control program. It is to be noted that the monitoring provided by the Bureau is a supplementto and not a replacement for inspections to be carried out by the Constructor or Operator.

The quality control program, as appropriate, is to include the following items:

Material quality and test requirements;

Linepipe manufacturing procedure specification and qualification;

Welder qualification and records;

Pre-welding inspection;

Chapter 1 Scope and Condition of ClassificationSection 8 Survey, Inspection and Testing 1-8


Welding procedure specifications and qualifications;

Weld inspection;

Tolerances and alignments;

Corrosion control systems;

Concrete weight coating;

Non-destructive testing;

Inspection and survey during pipe laying;

Final inspection and system pressure testing;

Pigging operations and tests;

Final as-built condition survey and acceptance.

1.5 Access and Notification

During fabrication and construction, the Bureau representatives are to have access to pipelines andrisers at all reasonable times. The Bureau is to be notified as to when and where linepipe, riserpipe,pipeline, riser and pipeline components may be examined. If the Bureau finds occasion to recommendrepairs or further inspection, notice will be made to the Contractor or his representatives.

1.7 Identification of Materials

The Contractor is to maintain a data system of material for linepipe, riserpipe, pipeline components,joints, anodes and coatings. Data concerning place of origin and results of relevant material tests areto be retained and made readily available during all stages of construction.

3 Inspection and Testing in Fabrication Phase

Specifications for quality control programs of inspection during fabrication of linepipe, riserpipe, andpipeline components are given in this section. Qualification tests are to be conducted to document thatthe requirements of the specifications are satisfied.

3.1 Material Quality

The physical properties of the linepipe material and welding are to be consistent with the specificapplication and operational requirements of pipelines and risers. Suitable allowances are to be addedfor possible degradation of the physical properties in the subsequent installation and operationactivities. Verification of the material quality is to be done by the Surveyor at the manufacturingplant, in accordance with Chapter 2 of this Guide. Alternatively, materials manufactured to recognizedstandards or proprietary specifications may be accepted by the Bureau, provided such standards giveacceptable equivalence with the requirements of this Guide.

3.3 Manufacturing Procedure Specification and Qualification

A manufacturing specification and qualification procedure is to be submitted for acceptance beforeproduction start. The manufacturing procedure specification is to state the type and extent of testing,the applicable acceptance criteria for verifying the properties of the materials and the extent and typeof documentation, record and certificate. All main manufacturing steps from control of received rawmaterial to shipment of finished linepipe, including all examination and checkpoints, are to bedescribed. The Bureau will survey formed linepipe, riserpipe, pipeline, riser and pipeline componentssuch as bends, tees, valves etc. for their compliance with the dimensional tolerances, chemicalcomposition and mechanical properties required by the design.



3.5 Welder Qualification and Records

Welders who are to work on pipelines and risers are to be qualified in accordance with the welderqualification tests specified in a recognized code such as API STD 1104 and Section IX of the ASME“Boiler and Pressure Vessel Code”. Certificates of qualification are to be prepared to record evidenceof the qualification of each welder qualified by an approved standard/code. In the event that weldershave been previously qualified in accordance with the requirements of a recognized code, andprovided that the period of effectiveness of previous testing has not lapsed, these welder qualificationtests may be accepted.

3.7 Pre-Welding Inspection

Prior to welding, each pipe is to be inspected for dimensional tolerance, physical damage, coatingintegrity, interior cleanliness, metallurgical flaws and proper fit-up and edge preparation.

3.9 Welding Procedure Specifications and Qualifications

Welding procedures are to conform to the provisions of a recognized code, such as API STD 1104, orowner’s specifications. A written description of all procedures previously qualified may be employedin the construction provided it is included in the quality control program, and made available to theBureau. When it is necessary to qualify a welding procedure, this is to be accomplished by employingthe methods specified in the recognized code. All welding is to be based on welding consumables andwelding techniques proven to be suitable for the types of material, pipe and fabrication in question. Asa minimum, welding procedure specification is to contain the following items:

Base metal and thickness range;

Types of electrodes;

Joint design;

Weld consumable and welding process;

Welding parameters and technique;

Welding position;

Preheating;

Interpass temperatures and post weld heat treatment.

For underwater welding, additional information is, if applicable, to be specified, including waterdepth, pressure, and temperature, product composition inside the chamber and the welding umbilicaland equipment.

3.11 Weld Inspection

As part of the quality control program, a detailed plan for the inspection and testing of welds is to beprepared.

The physical conditions under which welding is to proceed, such as weather conditions, protection,and the condition of welding surfaces, are to be noted. Alterations in the physical conditions may berequired should it be determined that satisfactory welding cannot be obtained.

Where weld defects exceed the acceptability criteria, they are to be completely removed and repaired.Defect acceptance criteria may be project specific as dictated by welding process, non-destructivetesting resolution and results of fatigue crack growth analysis. The repaired weld is to be reexaminedusing acceptable non-destructive methods.



3.13 Tolerances and Alignments

The dimensional tolerance criteria are to be specified in developing the linepipe manufacturingspecification. Inspections and examinations are to be carried out to ensure that the dimensionaltolerance criteria are being met. Particular attention is to be paid to the out-of-roundness of pipes forwhich buckling is an anticipated failure mode. Structural alignment and fit-up prior to welding are tobe monitored to ensure the consistent production of quality welds.

3.15 Corrosion Control Systems

The details of any corrosion control systems employed for pipelines and risers are to be submitted forreview. Installation and testing of the corrosion control systems are to be carried out in accordancewith the approved plans and procedures.

Where employed, the application and resultant quality of corrosion control coatings (external andinternal) are to be inspected to ensure that specified methods of application are followed and that thefinished coating meets specified values for thickness, lack of holidays (small parts of the structuralsurfaces unintentionally left without coating), hardness, etc. Visual inspection, micrometermeasurement, electric holiday detection or other suitable means are to be employed in the inspection.

3.17 Concrete Weight Coatings

Weight coatings applied when onshore or, if applicable, when on the lay vessel are to be inspected forcompliance with the specified requirements for bonding, strength and hardness, weight control, andany necessary special design features. Production tests are to be carried out at regular intervals toprove compliance with the specifications.

3.19 Non-destructive Testing

A system of non-destructive testing is to be included in the fabrication and construction specificationof pipelines and risers. The minimum extent of non-destructive testing is to be in accordance with thisGuide or a recognized design Code. All non-destructive testing records are to be reviewed andapproved by the Bureau. Additional non-destructive testing may be requested if the quality offabrication or construction is not in accordance with industry standards.

3.21 Fabrication Records

A data book of the record of fabrication activities is to be developed and maintained so as to compileas complete a record as is practicable. The pertinent records are to be adequately prepared andindexed in order to assure their usefulness, and they are to be stored in a manner that is easilyrecoverable.

As a minimum, the fabrication record is to include, as applicable, the following:

Manufacturing specification and qualification procedures records;

Material trace records (including mill certificates);

Welding procedure specification and qualification records;

Welder qualification;

Non-destructive testing procedures and operators certificates;

Weld and non-destructive testing maps;

Shop welding practices;

Welding inspection records;

Fabrication specifications;



Structural dimension check records;

Non-destructive testing records;

Records of completion of items identified in the quality control program;

Assembly records;

Pressure testing records;

Coating material records;

Batch No. etc.;

Concrete weight coating mix details, cube test etc.

The compilation of these records is a condition of certifying pipelines and risers.

After fabrication and assembly, these records are to be retained by the Operator or Fabricator forfuture reference. The minimum time for record retention is not to be less than the greatest of thefollowing:

Warranty period;

Time specified in fabrication and construction agreements;

Time required by statute or governmental regulations.

5 Inspection and Testing during Installation

This Section gives the specifications and requirements for the installation phase, covering routesurvey of pipelines and risers prior to installation, installation manual, installation procedures,contingency procedures, as-laid survey, System Pressure Test, final testing and preparation foroperation.

5.1 Specifications and Drawings for Installation

The specifications and drawings for installation are to be detailed and prepared giving the descriptionsof and requirements for the installation procedures to be employed. The requirements are to beavailable in the design premise, covering the final design, verification and acceptance criteria forinstallation and System Pressure Test, records and integrity of pipelines and risers. The drawings areto be detailed enough to demonstrate the installation procedures step by step. The final installationresults are to be included in the drawings.

5.3 Installation Manual

Qualification of installation manual is specified in 3-6/3 of this Guide.

5.5 Inspection and Survey During Pipe laying

Representatives from the Bureau are to witness the installation of pipelines and risers to ensure that itproceeds according to approved procedures.

5.7 Final Inspection and Pressure Testing

A final inspection of the installed pipelines and risers is to be completed to verify that it satisfies theapproved specifications used in its fabrication and the requirements of this Guide. If the pipeline is tobe buried, inspection will normally be required both before and after burial operations. Asappropriate, additional inspections, which may include those for the proper operation of corrosioncontrol systems, buckle detection by caliper pig or other suitable means, the testing of alarms,instrumentation, safety systems and emergency shutdown systems, are to be performed.



5.9 Inspection for Special Cases

Areas of pipelines and risers may require inspection after one of the following occurrences:

Environmental events of major significance;

Significant contact from surface or underwater craft, dropped objects, or floating debris;

Collision between risers in parallel or between risers and mooring lines;

Any evidence of unexpected movement;

Any other conditions which might adversely affect the stability, structural integrity or safetyof pipelines and risers.

Damage that affects or may affect the integrity of pipelines and risers is to be reported at the firstopportunity by the Operator for examination by the Bureau. All repairs deemed necessary by theBureau are to be carried out to their satisfaction.

5.11 Notification

The Operator is to notify the Bureau on all occasions when parts of pipelines and risers not ordinarilyaccessible, are to be examined. If at any visit a Surveyor should find occasion to recommend repairsor further examination, this is to be made known to the Operator immediately in order that appropriateaction may be taken.

7 Conditions for Surveys after Construction

7.1 Damage, Failure and Repair

7.1.1 Examination and Repair

Damage, failure, deterioration or repair of the Installation or its elements, which affectsclassification, is to be submitted by the Owners or their representatives for examination by theSurveyor at the first opportunity. All repairs found necessary by the Surveyor are to be carriedout to his satisfaction.

7.1.2 RepairsWhere repairs to pipelines or risers or connected elements thereto, which may affectclassification, are planned in advance to be carried out, a complete repair procedure includingthe extent of the proposed repair and the need for Surveyor’s attendance is to be submitted toand agreed upon by the Surveyor reasonably in advance. Failure to notify the Bureau, inadvance of the repairs, may result in suspension of classification until such time as the repairis redone or evidence submitted to satisfy the Surveyor that the repair was properly carriedout.

The above is not intended to include maintenance and overhaul in accordance withrecommended manufacturer’s procedures and established practice and which does not requireBureau approval; however, any repair as a result of such maintenance and overhauls whichaffects or may affect classification is to be noted in the unit’s log and submitted to theSurveyors as required.

7.1.3 RepresentationNothing contained in this Section or in a rule or regulation of any government or otheradministration, or the issuance of any report or certificate pursuant to this section or such arule or regulation, is to be deemed to enlarge upon the representations expressed in 1-1/1through 1-1/7 hereof and the issuance and use of any such reports or certificates are to begoverned in all respects by 1-1/1 through 1-1/7 hereof.



7.3 Notification and Availability for Survey

The Surveyors are to have access to classed pipelines and risers at all reasonable times. For thepurpose of Surveyor monitoring, monitoring Surveyors shall also have access to classed units at allreasonable times. Such access may include attendance at the same time as the assigned Surveyor orduring a subsequent visit without the assigned Surveyor. The Owners or their representatives are tonotify the Surveyors for inspection on all occasions, when parts of pipelines and risers not ordinarilyaccessible are to be examined.

The Surveyors are to undertake all surveys on classed systems upon request, with adequatenotification, of the Owners or their representatives and are to report thereon to the Committee. Shouldthe Surveyors find occasion during any survey to recommend repairs or further examination,notification is to be given immediately to the Owners or their representatives in order that appropriateaction may be taken. The Surveyors are to avail themselves of every convenient opportunity forcarrying out periodical surveys in conjunction with surveys of damages and repairs in order to avoidduplication of work.

9 In-service Inspection and SurveyThe phases of operation include operation preparation, inspection, survey, maintenance and repair.During the operation condition, in-service inspections and surveys are to be conducted for pipelinesand risers. The philosophy of such inspection and survey is to be established and submitted to theBureau for review. In-service inspections and surveys are to be planed to identify the actualconditions of pipelines and risers for the purpose of integrity assessment. In-service inspection can beplanned based on structural reliability methods.

11 Inspection for Extension of UseExisting pipelines and risers to be used at the same location for an extended period of time beyond theoriginal design life are to be subject to additional structural inspection in order to identify the actualcondition of the pipelines and risers. The extent of the inspection will depend on the completeness ofthe existing inspection documents. Any alterations, repairs, replacements or installation of equipmentsince installation are to be included in the records.

The minimum inspection generally covers examination of splash zone and end fittings for risers,examination and measurement of corrosion protection systems and marine growth, sea floor conditionsurvey, examination of secondary structural attachments and support systems. Special attention is tobe given to the following critical areas:

Highly stressed areas;

Areas of low fatigue life (splash zone and touch down point for risers, girth welds);

Areas with sub-sea structures, crossings and free spans;

End terminations, high bending areas and touch down point for risers;

Areas where damage was incurred during installation or while in service;

Areas where repairs, replacements or modifications were made while in service;

Areas where abnormalities were found during previous inspections.

The inspection schedule of the pipelines and risers can be planned based on the re-qualification or re-assessment of the systems applying, e.g. structural reliability methodology (see Appendix B), andincorporating past inspection records.



S E C T I O N 9 Fees

Fees in accordance with normal ABS practice will be charged for all services rendered by the Bureau.Expenses incurred by the Bureau in connection with these services will be charged in addition to thefees. Fees and expenses will be billed to the party requesting that particular service.



S E C T I O N 10 Disagreement

1 Guide

Any disagreement regarding either the proper interpretation of the Guide, or translation of the Guidefrom the English language edition, is to be referred to the Bureau for resolution.

3 Surveyors

In case of disagreement between the Owners or builders and the Surveyors regarding the material,workmanship, extent of repairs, or application of the Guide relating to any system classed or proposedto be classed by the Bureau, an appeal may be made in writing to the Committee, who will order aspecial survey to be held. Should the opinion of the Surveyor be confirmed, expense of this specialsurvey is to be paid by the party attending.



S E C T I O N 11 Limitation of Liability

The combined liability of the American Bureau of Shipping, its committees, officers, employees,agents or subcontractors for any loss, claim, or damage arising from its negligent performance ornonperformance of any of its services or from breach of any implied or express warranty ofworkmanlike performance in connection with those services, or from any other reason, to any person,corporation, partnership, business entity, sovereign, country or nation, will be limited to the greater ofa) $100,000 or b) an amount equal to ten times the sum actually paid for the services alleged to thedeficient.

The limitation of liability may be increased up to an amount twenty-five times that sum paid forservices upon receipt of Client’s written request at or before the time of performance of services andupon payment by Client of an additional fee of $10.00 for every $1,000.00 increase in the limitation.



S E C T I O N 12 Definitions

CONTENTS1 Classification ......................................................................... 49

3 Constructor or Contractor .................................................... 49

5 Extension of Use ................................................................... 49

7 Maximum Allowable Operating Pressure ............................ 49

9 Offshore ................................................................................. 49

11 Operator ................................................................................. 49

13 Owner ..................................................................................... 49

15 Pipeline .................................................................................. 50

17 Pipeline System..................................................................... 50

19 Recurrence Period or Return Period.................................... 50

21 Riser ....................................................................................... 50



S E C T I O N 12 Definitions

1 Classification

The term Classification, as used herein, indicates that an offshore installation has been designed,constructed, installed and surveyed in compliance with accepted Rules and Guides.

3 Constructor or Contractor

A Constructor or Contractor is any person or organization having the responsibility to perform any orall of the following: analysis, design, fabrication, inspection, testing, load-out, transportation andinstallation.

5 Extension of UseAn existing pipeline or riser used at the same location beyond its original design life.

7 Maximum Allowable Operating Pressure

The Maximum Allowable Operating Pressure is defined as the Design Pressure less the positivetolerance of the pressure regulation system.

9 Offshore

Offshore is the area seaward of the established coastline that is in direct contact with the open sea.

11 OperatorAn Operator is any person or organization empowered to conduct commissioning and operations onbehalf of the Owners of pipelines and risers.

13 OwnerAn Owner is any person or organization who owns pipelines and risers/facilities.

Chapter 1 Scope and Conditions of ClassificationSection 12 Definitions 1-12


15 Pipeline

A Pipeline is a primarily horizontal pipe lying on, near or beneath the seabed, normally used for thetransportation of hydrocarbon products.

17 Pipeline System

A Pipeline System is an integrated set of sub-sea flowlines and pipelines including pertinentinstrumentation, foundations, coatings, anchors, etc.

19 Recurrence Period or Return Period

The Recurrence Period or Return Period is a specified period of time that is used to establish extremevalues of random parameters such as wave height, for design of pipelines and risers.

21 Riser

A Riser is a conducting pipe connecting sub-sea wellheads, templates or pipelines to equipmentlocated on a buoyant or fixed offshore structure.


C H A P T E R 2 Materials and Welding

CONTENTSSECTION 1 Metallic Pipe ............................................................ 53

1 General................................................................... 55

3 Selection of Materials............................................. 55

5 Steel Linepipe......................................................... 56

7 Linepipe Materials for Special Applications ........... 57

9 Marking, Documentation and Transportation......... 57

SECTION 2 Piping Components and Pipe Coating .................. 59

1 General................................................................... 61

3 Piping Components................................................ 61

5 Pipe Coating........................................................... 62

7 Buoyancy Modules................................................. 64

SECTION 3 Welding of Pipes and Piping Components............ 65

SECTION 4 Corrosion Control ................................................... 67

1 General................................................................... 69

3 Corrosion Control ................................................... 69



S E C T I O N 1 Metallic Pipe


3 Selection of Materials............................................................ 55

5 Steel Linepipe ........................................................................ 56

5.1 Chemical Composition ........................................................... 56

5.3 Weldability .............................................................................. 56

5.5 Pipe Manufacture Procedure.................................................. 56

5.7 Fabrication Tolerance............................................................. 56

5.9 Fracture Arrest Toughness..................................................... 57

5.11 Mill Pressure Test................................................................... 57

7 Linepipe Materials for Special Applications ........................ 57

7.1 Sour Service ........................................................................... 57

7.3 Stainless, Duplex, and Super Duplex Stainless Steel Pipes.. 57

7.5 Clad Pipe ................................................................................ 57

7.7 Titanium Pipe.......................................................................... 57

9 Marking, Documentation and Transportation...................... 57



S E C T I O N 1 Metallic Pipe

1 GeneralThis Chapter specifies the linepipe material requirements, including steel pipes and other specialmetallic pipes used for pipeline and riser applications. Material and dimensional standards for metallicpipe are to be in accordance with this Guide with respect to chemical composition, materialmanufacture, tolerance, strength and testing requirements. A specification is to be prepared stating therequirements for materials and for manufacture, fabrication and testing of linepipes, including theirphysical properties.

3 Selection of Materials

The linepipe materials used under this Guide are to be carbon steels, alloy steels, or other specialmaterials, such as titanium, manufactured according to a recognized standard. The materials are to beable to maintain the structural integrity of pipelines and risers for hydrocarbon transportation underthe effects of service temperature and anticipated loading conditions. Materials in near vicinity are tobe qualified in accordance with applicable specifications for chemically compatibility.

The following aspects are to be considered in the selection of material grades:

Mechanical properties;

Internal fluid properties and service temperature;

Resistance to corrosion effects;

Environmental and loading conditions;

Installation methods and procedure;

Weight requirement;

Weldability;

Fatigue and fracture resistance.

Documentation for items such as formability, welding procedure, hardness, fatigue, fracture andcorrosion characteristics is to be submitted for Bureau review to substantiate the applicability of theproposed materials.

Chapter 2 Materials and WeldingSection 1 Metallic Pipe 2-1


5 Steel Linepipe

Material, dimensional standards and manufacturing process of steel pipe are to be in accordance withAPI SPEC 5L, ISO 3183-1~3 or other recognized standards. Approval by the Bureau is required forthe intended application, with respect to chemical composition, material manufacture, tolerances,strength and testing requirements.

5.1 Chemical Composition

The chemical composition of linepipes, as determined by heat analysis, is to conform to the applicablerequirements of the grade and type of steel material. However, the requirements of chemicalcomposition may be agreed upon between the Operator and the linepipe manufacturer.

5.3 Weldability

The carbon equivalent (Ceq) and the cold cracking susceptibility (Pcm) for evaluating the weldabilityof steel pipes may be calculated from the ladle analysis in accordance with the following equations(percentage of weight):

15

CuNi

5

VMoCr

6

Mn ++++++= CCeq

B510

V

15

Mo

60

Ni

20

CrCuMn

30

Si ++++++++= CPcm

Selection of Ceq and Pcm, as well as their maximum values, is to be agreed between the Operator andthe steel mill when the steel is ordered to ensure weldability. When low carbon content is used forsour service, the value of the cold cracking susceptibility (Pcm) is to be limited. However, the behaviorof steel pipe during and after welding is dependent on the steel, the filler metals used and theconditions of the welding process. Unless it can be documented otherwise, a testing program is to beperformed to qualify candidate linepipe materials and filler metals.

5.5 Pipe Manufacture Procedure

The fabrication procedures are to comply with an approved standard pertinent to the type of pipebeing manufactured. All non-destructive testing operations referred to in this Part are to be conductedby non-destructive testing personnel qualified and certified in accordance with standards such asASNT SNT-TC-1A, ISO 11484, or other applicable codes.

The manufacturer is to prepare a manufacturing procedure specification for review by the Bureau. Themanufacturing procedure specification is to document the forming techniques and procedures,welding procedures and welding testing, material identification, mill pressure testing, dimensionaltolerances, surface conditions and properties to be achieved and verified. Pipes are to be selected frominitial production for manufacturing procedure qualification through mechanical, corrosion and non-destructive testing.

5.7 Fabrication Tolerance

The fabrication tolerance may be agreed upon between the operator and the linepipe manufacturer, butis to be consistent with the design requirements. The pipes may be sized to their final dimensions byexpansion and straightening. The pipes are to be delivered to the dimensions specified in themanufacturing procedure.



5.9 Fracture Arrest Toughness

Fracture toughness values for crack arrest given in ISO codes and API RP are adequate for designfactors up to 72% and are given mainly for land based pipelines. The acceptance criteria for fracturearrest toughness of offshore pipelines are to be agreed upon between the operator and linepipemanufacture.

5.11 Mill Pressure Test

The mill test pressure and duration may be agreed upon between the Operator and the linepipemanufacturer, but is to be consistent with the design requirements. The mill pressure test is to beconducted after final pipe expansion and straightening.

7 Linepipe Materials for Special Applications

This Section defines the minimum requirements for linepipe materials such as carbon steel, stainlesssteel, duplex, clad carbon steel and titanium alloy for extreme temperatures, sour service or otherspecial applications.

7.1 Sour Service

Linepipe materials for sour (H2S-containing) service are to satisfy the criteria of NACE MR0175 forresistance to sulfide stress cracking and hydrogen induced cracking failures. Materials that are notlisted in NACE MR0175 are to be tested according to procedures NACE TM0177 and NACETM0284 for both materials and welds. The acceptance criteria are to be agree upon between theoperator and the linepipe manufacturer based on the intended service condition

7.3 Stainless, Duplex, and Super Duplex Stainless Steel Pipes

The chemical composition and the manufacturing of stainless steel pipes are to follow standards suchas ASTM A790. The manufacturer is to establish the manufacturing procedure for the pipes, which isto contain relevant information about steel manufacturing, pipe manufacturing, welding and controlmethods which are to follow recognized standards such as API SPEC 5LC. Mechanical tests are to beperformed after heat treatment, expansion and final shaping. Specific tests may be required to meetproject requirements.

7.5 Clad Pipe

Clad pipes are to be compatible with the functional requirements and service conditions as specifiedfor the project. Material dimensional standards and manufacturing process of clad steel pipe are to bein accordance with API SPEC 5LD or equivalent recognized standards.

7.7 Titanium Pipe

Specific compositional limits and tensile property minimums for titanium alloy tubular products maybe produced in accordance with ASTM B861 and ASTM B862 specifications. Titanium alloys arehighly corrosion resistant to produced well fluid, including all hydrocarbons, acidic gases (CO2 andH2S), elemental sulfur and sweet and sour chloride brines at elevated temperatures. Titanium alloysare also generally resistant to well, drilling and completion fluids.

9 Marking, Documentation and TransportationPipes are to be properly marked for identification by manufacture. The marks are to identify thestandard with which the product is in complete compliance, the size and weight designations, materialgrade and class, process of manufacture, heat number, and joint number.



Pipe storage arrangements are to preclude possible damage, such as indentations of the surface andedges of pipes. Materials are to be adequately protected from deleterious influences during storage.The temperature and humidity conditions for storing weld filler material and coating are to be incompliance with those specified in their controlling material specification or manufacturer’s suppliedinformation.

Documentation for all materials of the major components of pipelines and risers is to indicate that thematerials satisfy the requirements of the pertinent specification. Material tests are to be performed tothe satisfaction of the Bureau. Procedure for the transportation of the linepipes from the fabricationand coating yards to the offshore destination is to be established. Transportation of the pipes is tofollow the guidelines of API RP 5L1 and API RP 5LW.



S E C T I O N 2 Piping Components and PipeCoating


3 Piping Components............................................................... 61

3.1 Flanges................................................................................... 61

3.3 Pipe Fittings............................................................................ 61

3.5 Gaskets .................................................................................. 61

3.7 Bolting..................................................................................... 61

3.9 Valves..................................................................................... 61

3.11 Piping Supports and Foundations .......................................... 62

5 Pipe Coating .......................................................................... 62

5.1 Weight Coating....................................................................... 62

5.3 Insulation Coating................................................................... 62

5.5 Corrosion Coating .................................................................. 63

5.7 Field Joint Coating.................................................................. 63

7 Buoyancy Modules................................................................ 64



S E C T I O N 2 Piping Components and PipeCoating

1 General

The design of the pipeline and riser includes various piping components. Specifications for eachpiping component and coating material used on a pipeline system are to be identified. Thespecifications are to be submitted to the Bureau for approval if the components have special serviceconditions or deviate from the standards indicated in this Guide or other comparable codes.

3 Piping ComponentsThe piping components are to be suitable for the pipeline design conditions and be compatible withthe linepipes in material, corrosion and welding.

3.1 Flanges

Pipe flanges used for offshore pipelines and risers vary depending on the connection requirement sub-sea and at the surface to the platforms. Typical flange materials and dimensions are to follow ASMEB16.5, API SPEC 17D, and MSS SP-44 where applicable. The flange design may be determined bycalculations in accordance with Section VIII of the ASME Boiler and Pressure Vessel Code.

3.3 Pipe Fittings

Pipefittings are to match the design of the linepipes and flanges. Typical materials and dimensions areto follow ASME B16.9, B16.11, B16.25, MSS SP-75, and API SPEC 17D where applicable.

3.5 Gaskets

Gaskets are to match the design of the flanges. Typical materials and dimensions are to follow ASMEB16.20 and API SPEC 6A where applicable.

3.7 Bolting

The bolting is to match the design of the flanges. Typical materials, dimensions, and bolting torqueare to follow ASME B16.5 and API SPEC 6A where applicable.

3.9 Valves

The valves are to match the linepipes and flanges. Typical materials, dimensions are to follow ASMEB16.34, API STD 600, and API SPEC 6D.

Chapter 2 Materials and WeldingSection 2 Piping Components and Pipe Coating 2-2


3.11 Piping Supports and Foundations

Piping support and foundation design is to follow the appropriate criteria of ASME B31.4 and API RP2A-WSD.

5 Pipe Coating

Specifications for corrosion coatings and concrete weight coating are to be submitted to the Bureaufor approval if special service conditions exist. The weight coating specification is as a minimum toinclude:

Chemical composition;

Physical and strength properties;

Quality control procedures and verifying tests for manufacturing or production.

5.1 Weight Coating

Weight coating is, when applicable, to be applied to ensure vertical and horizontal on-bottom stabilityby providing negative buoyancy to the pipeline. The weight coating specification is to include:

Mechanical properties, including strength, density, durability, etc.;

Cement materials or equivalent;

Reinforcement, including type, amount and grade;

Concrete coating method to achieve homogeneous and adequately consolidated coating;

Curing method compatible with coating application;

Repairs of uncured or hardened defective concrete coatings;

Storage, handling and transportation of coated pipe.

Inspection and testing are to be carried out at regular intervals during weight coating application andconsideration is to be given to:

Mix proportions and water-cement ratio;

Concrete density and compressive strength;

Weight before and after concrete application;

Outer diameter of coated pipe;

Water absorption.

Stress concentration in the pipeline due to the weight coating is to be examined to avoid local damagein form of buckling or fracture during handling and laying operations.

5.3 Insulation Coating

Thermal insulation coatings may be required for pipelines, risers, spools, pipe-in-pipe systems andpipeline bundle systems to ensure flow assurance in which case a design and qualification program isto be submitted to the Bureau for review.

The thermal insulation design is to consider the coating material properties including:

Thermal conductivity;

Density;

Adhesion to base material;



Abrasion resistance;

Service pressure and temperature;

Impact resistance;

Creep;

Durability against chemical, physical or biological attack;

Water absorption;

Degradation during service.

Inspection is to be conducted both during surface preparation and after coating application.

5.5 Corrosion Coating

Corrosion coating materials are to be suitable for the intended use and consideration is to be given to:

Corrosion protective properties;

Temperature resistance;

Adhesion and disbonding properties in conjunction with cathodic protection;

Mechanical properties;

Impact resistance;

Durability;

Shear strength;

Tensile strength;

Sea water resistance;

Water absorption;

Dielectric resistance;

Compatibility with cathodic protection system;

Resistance to chemical, biological and microbiological effects;

Aging, brittleness and cracking;

Variation of properties with temperature and time;

Health and safety information and instruction according to national regulations.

The coating procedure is to be in compliance with appropriate standards and is to include the detailsof the pipe surface preparation, production parameters, material specifications, application and testingmethods inclusive acceptance criteria and details of cutback lengths and coating termination.

Before and after the coating application, inspection and testing are to be conducted by means ofholiday detection to identify discontinuities or other defects that may impair its performance.

5.7 Field Joint Coating

Field joint coating is to be placed on the pipe joint after completion of the welding and weld testing.Installation, inspection, and testing procedures for the field joint are to be developed and submitted tothe Bureau.



7 Buoyancy ModulesBuoyancy modules, which may be of lightweight materials or steel tanks, are to be rated to amaximum allowable water depth and are to withstand normal handling, transportation, installation andenvironmental loads and in the same time be reliable and easy to operate. The module size is to bedetermined based on the lift requirements together with considerations to handling and installationrequirements. Reaction rings, strapping, bolting etc. are to be corrosion resistant and able to transferthe lift force without damage to the structure under extreme operating conditions.

The buoyancy material is to provide the required buoyant lift over the intended service life,accounting for time dependent degradation of buoyancy.

As a minimum, the following parameters are to be considered in selection of buoyancy coating:

Maximum water depth of application;

Environmental conditions;

Service life;

Density of the buoyancy;

Dry weight (mass) in air;

Submerged weight (mass) in the water;

Lift force in water;

Loads acting through all operating phases.



S E C T I O N 3 Welding of Pipes and PipingComponents

The welding of metallic pipes is to be performed in accordance with approved welding proceduresthat have been qualified to produce sound, ductile welds of adequate strength and toughness. Weldingstandards comparable to API STD 1104 and Section IX of the ASME Boiler and Pressure VesselCode are to be employed in association with this Guide. For special pipe materials, the applicability ofthe API STD 1104 is to be examined and verified at all stages of welding, and any alternative methodsare to be submitted for review.

Welders are to be tested in accordance with the welder qualification tests specified in recognizednational codes, such as API STD 1104. Certificates of qualification are to be prepared to cover eachwelder when they are qualified by standards other than those of the Bureau, and such certificates areto be available for the reference of the Surveyors.

Before construction begins, details of the welding procedures and sequences are to be submitted forreview. The details are to include:

Base metal and thickness range;

Types of electrode;

Edge preparation;

Electrical characteristics;

Welding technique;

Proposed position and speed;

Preheating and post-weld heat treatment practices.

Welding procedures conforming to the provisions of an acceptable code may be qualified in thepresence of the Surveyor in accordance with the pertinent code. A written description of all pre-qualified procedures employed in the pipeline’s construction is to be prepared and made available tothe Surveyors.

When it is necessary to qualify a welding procedure, this is to be accomplished by employing themethods specified in an acceptable code, and in the presence of the Surveyor.



S E C T I O N 4 Corrosion Control


3 Corrosion Control.................................................................. 69

3.1 External Corrosion Control ..................................................... 69

3.3 Internal Corrosion Control ...................................................... 69

3.5 Corrosion Rate and Corrosion Allowance .............................. 70

3.7 Monitoring and Maintenance of Corrosion ControlSystems.................................................................................. 70



S E C T I O N 4 Corrosion Control

1 GeneralA corrosion control system analysis is to be performed to determine necessary protection measuresand to provide in-service performance criteria and procedure for maintaining the system. The analysisis to be submitted to the Bureau for review and approval.

This Chapter recommends guidelines for the establishment of corrosion mitigation procedures foroffshore pipelines and risers. The following publications are incorporated by reference for thedetection and mitigation of external and internal corrosion:

ASME B31.4, Chapter IX, Section A460- A463;

ASME B31.8, Chapter VIII, Section A860-A863.

3 Corrosion Control

3.1 External Corrosion Control

Adequate anti-corrosion coating and cathodic protection are to be provided for protection againstexternal corrosion and may include a galvanic anode system, an impressed current system, or both.Design considerations are to be given to:

Pipe surface area;

Environmental condition;

Suitability of galvanic anode systems under given marine environment;

Design life of galvanic anode systems;

How to minimize potential damage to the cathodic protection system during lifecycle;

Interference of electrical currents from nearby structures;

Necessity of insulating joints for electrical isolation of portions of the system;

Inspection requirements for rectifiers or other impressed current sources.

3.3 Internal Corrosion Control

Adequate measures are to be taken against internal corrosion. Proper selection of pipe material,internal coating, injection of a corrosion inhibitor, or a combination of such options are to beconsidered.

Chapter 2 Materials and WeldingSection 4 Corrosion Control 2-4


When necessary, internal corrosion may be mitigated by the following:

Running scrapers;

Dehydration;

Injection of corrosion inhibitors;

Use of bactericides;

Use of oxygen scavengers;

Use of internal coating compatible to the contents;

Use of corrosion resistant alloys.

3.5 Corrosion Rate and Corrosion Allowance

The selected pipe wall thickness may include a corrosion allowance, depending on the preference forsuch measures and their effects to control corrosion. Guidance for estimating corrosion rates andallowances is given Appendix 4.

3.7 Monitoring and Maintenance of Corrosion Control Systems

Corrosion rate and the effect of anti-corrosion systems are to be evaluated by applying a monitoringprogram. Remedial actions are to be taken based on the evaluation results.


C H A P T E R 3 Design

CONTENTSSECTION 1 Design Loads .......................................................... 73

1 General................................................................... 75

3 Definitions of Design Loads ................................... 75

SECTION 2 Geotechnical Conditions........................................ 77

1 General................................................................... 77

3 Pipe Penetration in Soil .......................................... 77

5 Soil Friction............................................................. 77

7 Breakout Force....................................................... 77

9 Soil Surveys ........................................................... 77

SECTION 3 Environmental Effects ............................................ 79

1 General................................................................... 81

3 Wind ....................................................................... 81

5 Current ................................................................... 82

7 Waves .................................................................... 83

9 Combinations of Wind, Current and Waves........... 83

11 Tides....................................................................... 85

13 Marine Growth........................................................ 85

15 Subsidence............................................................. 85

17 Scours .................................................................... 86

19 Seafloor Instability.................................................. 86

21 Seismic................................................................... 86

23 Sea Ice ................................................................... 86

25 Environmental Design Conditions.......................... 87

SECTION 4 Strength Criteria...................................................... 89

1 General................................................................... 91

3 Stress Criteria......................................................... 91

5 Global Buckling ...................................................... 93

7 Local Buckling/Collapse Under ExternalPressure and Bending............................................ 93

9 Propagating Buckles .............................................. 94

11 Fatigue ................................................................... 95

13 Out-of-roundness ................................................... 95

15 Allowable Stresses for Supports and Restraints.... 96

17 Installation .............................................................. 96


SECTION 5 Pipeline Rectification and Intervention Design .....97

1 General................................................................... 99

3 In-place Analysis .................................................... 99

5 On-bottom Stability............................................... 101

7 Free Spanning Pipeline........................................ 102

9 Upheaval and Lateral Buckling ............................ 103

11 Design for Impact Loads ...................................... 104

SECTION 6 Routing, Installation, Construction andTesting....................................................................105

1 Route Selection .................................................... 107

3 Installation Analysis.............................................. 108

5 Construction ......................................................... 110

7 System Pressure Testing and Preparation forOperation.............................................................. 111

SECTION 7 Special Considerations for Design of MetallicRisers .....................................................................113

1 Scope and Objectives .......................................... 115

3 Descriptions of Riser System ............................... 115

5 Design Conditions and Loads .............................. 116

7 Design Criteria...................................................... 116

9 Global Response Analysis ................................... 116

11 Riser Components Design ................................... 120

SECTION 8 Special Considerations for Pipe in PipeDesign ....................................................................123

1 General................................................................. 123

3 Design Criteria...................................................... 123

SECTION 9 Special Considerations for Pipeline BundleDesign ....................................................................125

1 General................................................................. 127

3 Functional Requirements ..................................... 127

5 Design Criteria for Bundle Systems ..................... 128



S E C T I O N 1 Design Loads


3 Definitions of Design Loads ................................................. 75

3.1 Environmental Loads.............................................................. 75

3.3 Functional Loads .................................................................... 75

3.5 Accidental Loads .................................................................... 76

TABLE 1 Categorization of Design Loads for Pipelines andRisers ......................................................................... 76



S E C T I O N 1 Design Loads

1 GeneralThis Chapter pertains to the identification, definition and determination of loads that are to beconsidered in the design of pipelines and risers. Loads generally acting on pipelines and risers arecategorizes into load classes and followed by more detailed descriptions in subsequent Chapters,together with acceptance criteria for the utilization of the pipe strength. The criteria cover only theplane pipe and for flanges and other connectors, other recognized standards such as the ASME Boilerand Pressure Vessel Code should be used.

3 Definitions of Design Loads

Loads acting on pipelines and risers can be divided into environmental, functional and accidentalloads.

3.1 Environmental Loads

Environmental loads are defined as loads imposed directly or indirectly by environmental phenomenasuch as waves, current, wind, ice and snow. In general, the environmental loads vary with time andinclude both static and dynamic components. The characteristic parameters defining environmentalloads are to be appropriate to the operational phases, such as transportation, storage, installation,testing and operation. Environmental loads and load effects are further described in Chapter 3,Sections 3 and 5.

3.3 Functional Loads

Functional loads are defined by dead, live and deformation loads occurring during transportation,storage, installation, testing, operation and general use.

Dead loads are loads due to the weight in air of principal structures (e.g. pipes, coating,anodes, etc.), fixed/attached parts and loads due to external hydrostatic pressure and buoyancycalculated on the basis of the still water level.

Live loads are loads that may change during operation, excluding environmental loads, whichare categorized separately. Live loads will typically be loads due to the flow, weight, pressureand temperature of containment.

Deformation loads are loads due to deformations imposed on pipelines and risers throughboundary conditions such as reel, stinger, rock berms, tie-ins, seabed contours, constraintsfrom floating installations (risers), etc.

Chapter 3 DesignSection 1 Design Loads 3-1


The functional loads are to be determined for each specific operation expected to occur during thepipeline and riser life cycle and are to include the dynamic effects of such loads as necessary. Loadand load effects are further described in Chapter 3, Sections 2 and 5. In addition, extreme values oftemperatures expressed in terms of recurrence periods and associated highest and lowest values are tobe used in the evaluation of pipe materials.

3.5 Accidental Loads

Accidental loads are defined as loads that occur accidentally due to abnormal operating conditions,technical failure and human errors. Examples are soil sliding, earthquakes, mooring failure (for risers)and impacts from dropped objects, trawl board or collision. It is normally not necessary to combinethese loads with other environmental loads, unless site-specific conditions indicate such requirement.Dynamic effects are to be properly considered when applying accidental loads to the design. Risk-based analysis and past experience may be used to identify the frequency and magnitude of accidentalloads. Accidental loads and load effects are further described in Chapter 3, Section 5.

Typical design loads may be categorized in accordance to 3-1/Table 1.

TABLE 1Categorization of Design Loads for Pipelines and Risers

Environmental Loads Functional Loads Accidental Loads

Wind

Waves

Current

Tides

Surge

Marine growth

Subsidence

Scours

Seafloor instability

Seismic

Sea ice

Soil liquefaction

Weight in air of:- Pipe;- Coating ;- Anodes;- Attachments;- Etc.

Buoyancy

Towing

External hydrostatic pressure

Internal pressures:- Mill pressure test;- Installation;- Storage, Empty/water filled;- Inplace pressure test;- Operation.

Installation tension (pipes)

Top tension (risers)

Boundary conditions:- Reel;- Stinger;- Tie ins;- Rock berms;- Seabed contours;- Top constraints (risers);- Etc.

Soil interaction

Loads due to containment:- Weight;- Pressure;- Temperature;- Fluid flow, surge and slug.

Inertia

Pigging and run tools

Impacts from:- Dropped objects;- Trawl board;- Collision.

Soil sliding

Mooring failure (risers)

Loss of floating installation stationkeeping capability (risers)



S E C T I O N 2 Geotechnical Conditions

1 GeneralThe seabed stiffness and soil friction definition where the contact pressure between pipes and seabedgoverns the friction force can generally describe the interaction between the seabed and thepipeline/riser. The geotechnical conditions are an important part of establishing the pipe/soilinteraction model for in-place analysis, which is further discussed in Chapter 3, Section 5.

3 Pipe Penetration in SoilThe penetration of a statically loaded pipe into soil can be calculated as a function of pipe diameter,vertical contact pressure, the un-drained shear strength and submerged soil density. The circular formof pipelines and risers leads to a combined effect of friction and bearing capacity resisting soilpenetration.

In order to represent the soft nature of the seabed, a pressure/penetration relationship can be used, tospecify pipelines or risers penetration as a function of the ground pressure (force per unit length of thepipeline).

5 Soil FrictionBi-axial soil friction data are to, when applicable, be used for in-place analysis. Both pipelinepenetration of the seabed and build up of loose sediments due to lateral movement may lead to extralateral soil resistance. The degree of penetration/build up is dependent on the soil type and stiffnessand is to be considered in the friction model.

7 Breakout Force

The breakout force is the maximum force needed to move a pipe from its stable position on theseabed. This force can be significantly higher than the force needed to maintain the movement afterbreakout, depending on the soil type and degree of penetration. Reasonable breakout forces are to beused in in-place analyses.

9 Soil Surveys

Seabed soil is to be sampled at appropriate intervals and locations along with the bathymetricalsurveys. Normally only the upper 2 m are of interest for pipelines and risers, with special attentionpaid to the top 10 cm, where accurate data will improve the stability evaluation.



S E C T I O N 3 Environmental Effects


3 Wind ....................................................................................... 81

5 Current ................................................................................... 82

7 Waves..................................................................................... 83

9 Combinations of Wind, Current and Waves ........................ 83

11 Tides....................................................................................... 85

13 Marine Growth ....................................................................... 85

15 Subsidence ............................................................................ 85

17 Scours .................................................................................... 86

19 Seafloor Instability ................................................................ 86

21 Seismic................................................................................... 86

23 Sea Ice.................................................................................... 86

25 Environmental Design Conditions ....................................... 87

25.1 Normal Operating Condition with Pipeline or Riser in theNormal Intact Status............................................................... 87

25.3 Temporary Condition.............................................................. 87

25.5 Abnormal/Accidental Operating Condition ............................. 88

25.7 Fatigue.................................................................................... 88



S E C T I O N 3 Environmental Effects

1 GeneralDesign environmental conditions are to be defined by the operator together with oceanographicspecialists and approved by the Bureau. All foreseeable environmental phenomena that may influencethe pipeline and/or riser integrity are to be described in terms of their characteristic parametersrelevant to operational and strength evaluations.

Field and model generated data are to be analyzed by statistical and mathematical models to establishthe range of pertinent variations of environmental conditions to be employed in the design. Methodsemployed in developing available data into design criteria are to be described and submitted inaccordance with Chapter 1, Section 2. Probabilistic methods for short-term, long-term and extreme-value predictions employing statistical distributions are to be evidenced by relevant statistical tests,confidence limits and other measures of statistical significance. Hindcasting methods and models areto be fully documented. Due to the uncertainty associated with the definition of some environmentalprocesses, studies based on a parametric approach may be helpful in the development of designcriteria.

Generally, suitable environmental data and analyses will be accepted as the basis for design whenfully documented with sources, date and estimated reliability noted. For pipelines and risers in areaswhere published design standards and data exist, such standards and data may be cited as reference.

3 Wind

Wind forces are exerted upon parts of risers that are above the water surface and marine structures towhich risers might be attached. Statistical wind data is normally to include information on thefrequency of occurrence, duration and direction of various wind speeds. For design cases where theriser is attached to a floating installation, it might also be necessary to establish the spectrum of windspeed fluctuation for comparison with the structure’s natural sway periods.

Long-term and extreme-value predictions for winds are to be based on recognized techniques andclearly described. Vertical profiles of horizontal wind are to be determined based on recognizedstatistical or mathematical models. Published data and data from nearby land and sea stations may beused if available. Wind data are in general to refer to a specified reference level and averaging time.During design, the wind data may be adjusted to any specified averaging time and elevation based onstandard profiles and gust factors, such as given in API RP 2A-WSD.

Wind loads and local wind pressures are to be determined based on analytical methods or wind tunneltests on a representative model of the riser system. In general, gust wind loads, which are loads basedon wind speeds averaged over one-minute or less are to be used in the riser design combined withother simultaneous environmental loads acting on the riser and floating installation to which the risermay be attached. When appropriate, dynamic effects due to the cyclic nature of gust wind and cyclic

Chapter 3 DesignSection 3 Environmental Effects 3-3


loads due to vortex induced vibrations, including both drag and lift components, are to beinvestigated. For risers with negligible dynamic response to wind, a one-hour sustained wind speedmay be used to calculate the wind loads.

For winds normal to the riser axis, the following relation may be used to calculate the wind load:

AVCg

cF ys

aw ⋅⋅⋅

⋅

= 2

2

where

Fw = wind load

g = gravitational acceleration

ca = weight density of air

Cs = shape coefficient (dimensionless, = 0.50 for cylindrical sections)

Vy = wind speed at altitude y

A = projected area of pipe on a plane normal to the direction of the considered force

As an alternative to applying wind loads, the effect of wind can be accounted for indirectly throughthe modeling of floating installation offset and slow drift movement.

5 CurrentCurrent may be a major contributor to both static and dynamic loading on pipelines and risersinstalled at any depth. The current velocity and direction profile at a given location may have severalcontributions of which the most common are:

Oceanic scale circulation patterns;

Lunar/astronomical tides;

Wind and pressure differential generated storm surge;

River outflow.

The vector sum of all current components at specified elevations from the seafloor to the watersurface describes the current velocity and direction profile for the given location. The current profilemight be seasonally dependent, in which case this is to be accounted for in the design.

For riser design, the total current profile associated with the sea state producing extreme waves is tobe used in design analyses, while for pipelines, it will be enough to know the current profileassociated with extreme waves at a level near the seafloor. The current velocity and direction doesnormally not change rapidly with time and may be treated as time invariant for each sea state.

On-site data collection may be required for previously unstudied areas and/or areas expected to haveunusual or severe current conditions. If the current profile is not known from on-locationmeasurements, but is judged not to be severe for the design, the current velocity at a given depth maybe established using a velocity profile formulation. Current velocity profiles are to be based on site-specific data or recognized empirical relationships and the worst design direction is to be assumed.



7 WavesWaves are a major source of dynamic loads acting on risers and pipelines located in shallow waters(normally less than 150 m.), and their description is therefore of high importance. Statistical site-specific wave data, from which design parameters are to be determined, are normally to include thefrequency of occurrence for various wave height groups and associated wave periods and directions.For areas where prior knowledge of oceanographic conditions is insufficient, the development ofwave-dependent design parameters is to be performed in corporation with experienced specialists inthe fields of meteorology, oceanography and hydrodynamics.

For a fully developed sea, waves may be represented using the Pierson-Moskovitz spectrum, while theJONSWAP spectrum normally will be applicable for less developed seas. In the calculation ofspectrum moments, a proper cut-off frequency based on a project defined confidence level is to beapplied. Wave scatter diagrams can be applied to describe the joint probability of occurrence of thesignificant wave height and the mean zero crossing period. Where appropriate, alternative traditionalregular wave approaches may be used.

When dealing with extreme response estimations, the regular design wave heights are to be based onthe maximum wave height of a given return period, e.g. 1, 10 or 100 years, found from long termwave statistics. The estimation of the corresponding extreme wave period is in general more uncertaindue to lack of reliable data, and it is consequently recommended that the wave period is varied over arealistic interval in order to ensure that all extreme wave case have been considered. For systems withobvious unfavorable wavelengths and periods due to geometry or eigen-frequencies, the design waveperiod can be identified based on such criteria, while the wave height follows from breaking wavecriteria or statistical considerations.

Long term response statistics are to be applied in fatigue damage assessment, whereby the waveclimate is represented by a scatter diagram of the joint probability of the sea state vector and the wavespectrum, defined by significant wave height, peak period, and main wave direction. A simplifiedrepresentation of the long-term distribution for the response may be based on the frequency domainmethod consisting of:

Establishing an approximate long-term response distribution based on stochastic dynamicanalyses;

Calculation of an approximate lifetime extreme response;

Identification of the design storm;

Estimation of lifetime maximum response based on time domain simulations.

In analysis, a sufficient range of realistic wave periods and wave crest positions relative to pipelinesand risers are to be investigated to ensure an accurate determination of the maximum wave loads.Consideration is also to be given to other wave-induced effects, such as wave impact loads, dynamicamplification and fatigue. The need for analysis of these effects is to be assessed on the basis of theconfiguration and behavioral characteristics of pipelines and risers, the wave climate and pastexperience.

9 Combinations of Wind, Current and Waves

The worst combination of wind, current and waves are to be addressed in the design. When currentand waves are superimposed, the current velocity and direction are to be added as vectors to the wave-induced particle velocity and direction prior to computation of the total force, and where appropriate,flutter and dynamic amplification due to vortex shedding are to be taken into account.



For pipelines and risers having small diameters compared to the wave lengths being considered, semi-empirical formulations such as Morison's equation are considered to be an acceptable basis fordetermining the hydrodynamic force acting on a pipe:

iD FFF +=

where

F = hydrodynamic force vector per unit length along pipes

FD = hydrodynamic drag force vector per unit length

Fi = hydrodynamic inertia force vector per unit length

The drag force vector for a stationary pipe is given by:

nnDD uuCODg

cF ⋅⋅⋅⋅

⋅=

2

where

c = weight density of water

g = gravitational acceleration

OD = total external diameter of pipe including coating etc.

CD = drag coefficient (dimensionless)

un = component of the total fluid velocity vector normal to the axis of pipes

The inertia force vector for a stationary pipe is given by:

nMi aCOD

g

cF ⋅⋅

⋅⋅=4

2π

where

CM = inertia coefficient based on the displaced mass of fluid per unit length(dimensionless)

an = component of the total fluid acceleration vector normal to the axis of pipes

The lift force vector for a stationary pipe located on or close to the seabed is given by:

Aug

cCF nLL ⋅⋅

⋅

⋅= 2

2

where

FL = lift force per unit length

CL = lift coefficient (dimensionless)

A = projected area per unit length in a plane normal to the direction of the force

For risers that exhibit substantial rigid body oscillations due to the wave action, the modified form ofMorison's equation given below may be used to determine the hydrodynamic force:



( ) ( )nnmnnnnnDD aaCOD

g

ca

OD

g

cuuuuCOD

g

cFFF −⋅⋅

⋅⋅

+⋅

⋅⋅

+−⋅−⋅⋅⋅

⋅

=+=442

22 ππ

where

nu = component of the velocity vector of riser normal to its axis

Cm = added mass coefficient, i.e., Cm = CM – 1

na = component of the acceleration vector of the riser normal to its axis

The values of un and an are to be determined using recognized wave theory appropriate to the waveheights, wave periods, and water depth at the installation location, as well as the elevation at whichthe load is calculated.

For pipelines located on or close to the seabed, the hydrodynamic force coefficients CD, CM and CL

will vary as a function of the gap.

11 Tides

Tides, when relevant, are to be considered in the design of pipelines and risers. Tides may beclassified as lunar or astronomical tides, wind tides and pressure differential tides. The combination ofthe latter two is defined as storm surge and the combination of all three, storm tide. The water depth atany location consists of the mean depth, defined as the vertical distance between the seabed and anappropriate near-surface datum, and a fluctuating component due to astronomical tides and stormsurges. The highest and the lowest astronomical tide bound the astronomical tide variation. Still waterlevel is to be taken as the sum of the highest astronomical level plus the storm surge. Storm surge is tobe estimated from available statistics or by mathematical storm surge modeling.

13 Marine GrowthMarine growth may accumulate and is to be considered in the design of pipelines and risers. Thehighest concentrations of marine growth will generally be seen near the mean water level with anupper bound given by the variation of the daily astronomical tide and a lower bound, dependent onlocation, of more than 80 meters. Estimates of the rate and extent of marine growth may be based onpast experience and available field data. Particular attention is to be paid to increases in hydrodynamicloading due to the change of:

External pipe diameter;

Surface roughness;

Inertial mass;

Added weight.

Consideration is also to be given to the fouling effects likely on corrosion protection coatings.

15 Subsidence

The effects of seafloor subsidence are to be considered in the overall design when pipelines and risersare installed in areas where unique geological conditions exist. This will be an area where, forexample, significant seafloor subsidence could be expected to occur as a result of depletion of thesubsurface reservoir. The magnitude and time scale of subsidence are in such cases to be estimatedbased on geologic studies.



17 ScoursThe seafloor contours in installation areas may change considerable over time due to scour erosion,which is removal of soil due to current and waves caused either by natural geological processes or bystructural elements interrupting the flow regime near the seafloor. When applicable, the magnitudeand time scale of scour erosion is to be estimated based on geologic studies and its impact on designappropriately accounted for. When the magnitude of scour erosion makes it difficult to account for indesign, a proper survey program and routines for evaluating observed seafloor changes is to beestablished.

19 Seafloor InstabilitySeafloor instability may be seen under negligible slope angles in areas with weak, under-consolidatedsediments. Movements of the seafloor may be activated as a result of loads imposed on the soil due topipeline installation, change in pipeline operating conditions, wave pressure, soil self weight,earthquakes or combinations of these phenomena. When applicable, such areas are to be localized byproper surveys and precautions such as rerouting taken in the design.

21 SeismicThe seismic activity level for the pipeline and riser installation area is to be evaluated based onprevious records or detailed geological investigations. For pipelines and risers located in areas that areconsidered seismically active, the effects of earthquakes are to be considered in the design. Anearthquake of magnitude that has a reasonable likelihood of not being exceeded during the design lifeis to be used to determine the risk of damage, and a rare intense earthquake is to be used to evaluatethe risk of structural failure. These earthquake events are referred to as the Strength Level andDuctility Level Earthquakes respectively. The magnitudes of the parameters characterizing theseearthquakes, having recurrence periods appropriate to the design life of the pipelines and risers, are tobe determined. The effects of earthquakes are to be accounted for in design but, generally, need not betaken in combination with other environmental factors.

The strength level and ductility level earthquake-induced ground motions are to be determined on thebasis of seismic data applicable to the installation location. Earthquake ground motions are to bedescribed by either applicable ground motion records or response spectra consistent with therecurrence period appropriate to the design life of pipelines and risers. Available standardized spectraapplicable to the region of the installation site are acceptable provided such spectra reflect site-specific conditions affecting frequency content, energy distribution, and duration. These conditionsinclude the type of active faults in the region, the proximity to the potential source faults, theattenuation or amplification of ground motion, and the soil conditions.

The ground motion description used in design is to consist of three components corresponding to twoorthogonal horizontal directions and the vertical direction. All three components are to be applied topipelines and risers simultaneously.

As appropriate, effects of soil liquefaction, shear failure of soft mud and loads due to acceleration ofthe hydrodynamic added mass by the earthquake, mud slide, tsunami waves and earthquake generatedacoustic shock waves are to be accounted for in the design.

23 Sea IceFor arctic and sub-arctic areas, sea ice may be experienced in form of first year sheet ice, multi-yearfloes, first-year and multiyear pressure ridges, and/or ice islands. The strength of sea ice depends onfeatures such as composition, temperature, salinity and speed of load application. The effect of sea iceon risers is to consider the frozen-in condition (winter), breakout in the spring and summer pack iceinvasion as applicable.



Impact, both centric and eccentric, is to be considered where moving ice may impact risers. Impactanalysis is, as applicable, to consider both that of large masses (multi-year floes and icebergs) movingunder the action of current, wind, and Coriolis effect and that of smaller ice masses which areaccelerated by storm waves. The impact analysis is to consider mass, hydrodynamic added mass andshape of the ice, its velocity and its direction relative to risers.

The mode of ice failure (tension, compression, shear, etc.) depends on the shape and roughness of thesurface and the presence of frozen ice, as well as the ice character, crystallization, temperature,salinity, strain rate and contact area. The force exerted by the broken or crushed ice in moving past isto be considered. Limiting force concepts may be employed if thoroughly justified by calculations.

More details about conditions that are to be addressed in design and construction for arctic and sub-arctic offshore regions can be found in API RP 2N.

25 Environmental Design ConditionsIn this Guide, the combination of environmental factors producing the most unfavorable effects onpipelines and risers, as a whole and as defined by the parameters given above, is referred to as theEnvironmental Design Conditions.

The combination and severity of environmental conditions for use in design are to be appropriate tothe pipelines and risers and consistent with the probability of simultaneous occurrence of theenvironmental phenomena. It is to be assumed that environmental phenomena may approach pipelinesand risers from any direction unless reliable site-specific data indicate otherwise. The direction, orcombination of directions, which produces the most unfavorable effects on pipelines and risers is tobe accounted for in the design, unless there is a reliable correlation between directionality andenvironmental phenomena.

When applicable, it is recommended that at least the following environmental conditions are coveredby pipeline and riser analyses:

25.1 Normal Operating Condition with Pipeline or Riser in the Normal Intact Status

i) Worst combination of 1 years wind, wave, current and tide;

ii) Environmental condition of 100 years wave plus 10 years current;

iii) Environmental condition of 10 years wave plus 100 years current;

iv) Realistic values for marine growth;

v) Realistic values for loads due to sea ice;

vi) Realistic values for earthquakes.

25.3 Temporary Condition

The following are to be checked:

i) Transportation condition

Geometrical imperfections such as dents and out-of-roundness introduced by loads appliedduring transportation are to be considered.

ii) Installation/retrieval condition

Varying amount deployed;

With air or water filled;

Environmental condition of 1-year wave and current or trustable weather forecasts.



iii) System pressure test

Loads (especially pressure loads) during system pressure test.

iv) Shut-down and start-up

The fatigue evaluation is to include loads induced by shutdown and startup.

v) Pigging condition

Loads induced by pigging operations are to be considered.

25.5 Abnormal/Accidental Operating Condition

The following conditions are to be checked when applicable:

i) Impacts;

ii) Soil Sliding;

iii) Fire and explosion;

iv) Mooring failure (risers);

v) Tension failure (risers);

vi) Loss of floating installation station keeping capability (risers).

25.7 Fatigue

Adequate loading conditions are to be used for fatigue load effect analysis, including:

i) Significant wave;

ii) Vortex-induced vibrations;

iii) Cyclic loading induced during installation and operation.



S E C T I O N 4 Strength Criteria


3 Stress Criteria........................................................................ 91

3.1 Hoop stress criteria ................................................................ 91

3.3 Longitudinal Stress................................................................. 92

3.5 Equivalent Stress ................................................................... 92

3.7 Usage Factors ........................................................................ 93

5 Global Buckling ..................................................................... 93

7 Local Buckling/Collapse Under External Pressure andBending.................................................................................. 93

9 Propagating Buckles............................................................. 94

11 Fatigue ................................................................................... 95

13 Out-of-roundness .................................................................. 95

15 Allowable Stresses for Supports and Restraints ................ 96

17 Installation ............................................................................. 96

TABLE 1 Usage Factors η for Pipelines and Risers................ 93



S E C T I O N 4 Strength Criteria

1 GeneralThis Chapter defines strength criteria, which are to be applied as limits for the design of pipelines andrisers. The criteria are applicable for wall-thickness design as well as installation and in-placeanalyses. Alternative strength criteria based on recognized codes/standards, mechanical tests oradvanced analysis methods such as listed in the Appendices may be applied in the design based onapproval by the Bureau. If alternative strength criteria are applied in the design consistency is to bemaintained, e.g. are burst, local buckling and propagation buckling strength closely related.

The strength criteria listed in this Chapter follow a working stress design approach and cover thefollowing failure modes:

Yielding;

Local buckling;

Global buckling;

Fatigue;

Cross sectional out-of-roundness.

3 Stress Criteria

3.1 Hoop stress criteria

In selecting pipe wall-thickness, consideration is to be given to pipe structural integrity and stabilityduring installation, system pressure test and operation, including pressure containment, localbuckling/collapse, global buckling, on-bottom stability, protection against impact loads and free spanfatigue, as well as high temperature and uneven seabed induced loads.

The internal pressure containment requirements, often used as a basis for wall-thickness design, aregiven in form of a maximum allowable hoop stress σh:

Th kSMYS ⋅⋅= ησ

where

SMYS = Specified Minimum Yield Strength of the material

kT = temperature dependent material strength de-rating factor (to be based on materialtests or recognized codes such as ASME B31.8 for steel pipes)

η = usage factor (see 3-4/Table 1)

Chapter 3 DesignSection 4 Strength Criteria 3-4


The hoop stress σh for pipes is to be determined by:

t

tDpp eih ⋅

−⋅−=2

)()(σ

where

σh = hoop stress

pi = internal or external design pressure

pe = external design pressure

D = nominal outside steel diameter of pipe

t = nominal pipe wall thickness

When a corrosion allowance is included in the design to account for corrosive fluids, the corrosionallowance is to be subtracted from the nominal pipe wall thickness in the hoop stress calculation.

For thick walled pipes with a D/t < 20 the above hoop stress criteria may be adjusted based on e.g.BSI BS 8010-3.

Other methods, such as the limit state design defined in API RP 1111, may be used for the internalpressure containment requirements subject to Bureau approval.

3.3 Longitudinal Stress

To ensure structural integrity against longitudinal forces, the following longitudinal stress criteria areto be satisfied:

TkSMYS ⋅⋅≤ ησ

where

σ = longitudinal stress

SMYS = Specified Minimum Yield Strength of the material

kT = temperature dependent material strength de-rating factor (to be based on materialtests or recognized codes such as ASME B31.8)

η = usage factor (see 3-4/Table 1)

3.5 Equivalent Stress

The equivalent stress, also referred to as the stress intensity, is at any point in the pipe to satisfy thefollowing:

Thhhe kSMYS ⋅⋅≤⋅+⋅−+= ησσσσσσ 222 3

where

σe = equivalent stress

σ = longitudinal normal stress

σh = hoop stress (normal stress circumference direction)

σ h = shear stress due to shear force and torsional moment

kT = temperature dependent material strength de-rating factor (to be based on materialtests or recognized codes such as ASME B31.4 and B31.8)



η = usage factor for equivalent stress (see 3-4/Table 1)

3.7 Usage Factors

The usage factors to be used in the strength design are listed in 3-4/Table 1.

TABLE 1Usage Factors η for Pipelines and Risers

Hoop stress Long. stress Equivalent stress

Oil & Gas pipelines and oil risers 0.72 0.80 0.90

Gas risers connected unmanned platform 0.60 0.80 0.90

Gas risers connected manned platform 0.50 0.80 0.90

Alternatively to the factors in 3-4/Table 1, criteria based on ASME B31.4 and AMSE B31.8 may beapplied or for risers attached to a floating installation API RP 2RD.

5 Global Buckling

Internal overpressure and increased operating temperatures may aggravate build up of compressiveforces in a pipeline, which after start-up or after repeated start-up/shut-down cycles may lead to globalbuckling of the pipeline. This effect is to be explicitly dealt with in the design either by advancedanalysis predicting the position and amplification of buckles or by demonstrating that the build up ofcompressive force is less than the force needed to initiate global buckling.

7 Local Buckling/Collapse Under External Pressure andBending

For installation and temporary conditions where the pipe may be subjected to external overpressure,cross sectional instability in form of local buckling/collapse is to be checked. For pipes, with a D/tless than 50 and subjected to external overpressure combined with bending, the following strain checkis to be applied:

ηεε ≤

−+

c

ie

b p

pp8.0

where

ε = extreme fiber strain in the pipe

εb =D

t

⋅2

pe = external pressure

pi = internal pressure

η = usage factor applied to bending strain

and pc is to be calculated based on:

020

223 =⋅+⋅

⋅⋅+−⋅− pecpepcec ppp

t

Dfpppppp



where

pe = 3

21

2

⋅

−⋅

D

tE

υ

pp = D

tSMYSk fab

⋅⋅⋅ 2

f0 = out-of-roundness, (Dmax – Dmin)/D, not to be taken less than 0.5 %.

An out-of-roundness higher than 3% is not allowed in the pipe without further analysis consideringcollapse under combined loads, propagating buckling and serviceability of the pipe.

SMYS = Specified Minimum Yield Strength

E = Young’s Module

ν = Poisson’s ratio

kfab = material resistance de-rating factor due to fabrication

Selection of usage factor η is to be based on uncertainties in load effects, available means to detectand repair potential local buckles and the control of buckle propagation through use of bucklearrestors and are to be approved by the Bureau. When available information on load effects is limited,η is to be set to 0.6.

The material strength in the hoop direction will be influenced by the manufacturing process and if notest data are available for the hoop strength the following values for the reduction factor are to beused:

kfab =

pipes UOEe.g. pipes, expanded and Welded85.0

pipes UOe.g. expanded,not pipes Welded93.0

pipes annealed and Seemless00.1

De-rating due UO or UOE may be compensated for by additional heat treatment.

9 Propagating BucklesDuring installation or, in rare situations, shutdown of pipelines and risers, local buckles/collapse maystart propagating along the pipe with extreme speed driven by the hydrostatic pressure of seawater.Buckle arrestors may be used to stop such propagating buckles by confining a buckle/collapse failureto the interval between arrestors. Buckle arrestors may be designed as devices attached to or welded tothe pipe or they may be joints of thicker pipe. Buckle arrestors will normally be spaced at suitableintervals along the pipeline for water depths where the external pressure exceeds the propagatingpressure level.

Buckle arrestors are to be used when:

pe – pi ≥ 0.72 ⋅ ppr

where

ppr = 5.2

26

⋅⋅⋅

D

tSMYS , Buckle propagation pressure

Buckle arrestors are, when required, to be designed according to recognized codes, such as API RP1111



11 FatiguePipelines and risers may be subjected to fatigue damage throughout their entire life cycle. The maincauses to fatigue are normally effects of:

Installation;

Startup and shutdown cycles;

Wave and current conditions.

The fatigue life may be predicted using a S-N curve approach and is not to be less than ten times thedesign life for the pipeline or riser. This implies for the fatigue equations listed in this Guide that themaximum allowable damage ratio η is not to be taken higher than 0.1. A value higher than 0.1 may beaccepted if documentation for inspection, improvement in welding, workmanship etc is provided andaccepted by the Bureau.

Typical steps required for fatigue analysis using the S-N approach are outlined below.

i) Estimate long-term stress range distribution;

ii) Select appropriate S-N curve;

iii) Determine stress concentration factor;

iv) Estimate accumulated fatigue damage using Palmgren-Miner’s rule.

η≤=∑=

cM

i i

ifat N

nD

1

where

Dfat = accumulated fatigue damage

η = usage factor for allowable damage ratio

Ni = number of cycles to failure at the ith stress range defined by the S-N curve

ni = number of stress cycles with stress range in block i

The maximum allowable damage ratio may be relaxed if detailed analysis based on fracturemechanics or reliability-based calibration demonstrates that the target safety level is fulfilled with ahigher allowable damage ratio. Also, documentation demonstrating detailed fatigue inspection andplanning may lead to the acceptance of a higher allowable damage ratio. The use of anddocumentation for using a higher allowable damage ratio is to be submitted to and approved by theBureau.

Whenever possible, S-N curves based on HSE offshore installations: Guidance on Design,Construction and Certification are to be applied.

Fatigue assessment may be based on nominal stress or hot-spot stress. When the hot spot stressapproach is selected, stress concentration factors due to e.g. misalignment, are to be estimated usingappropriate stress analysis or stress concentration factor equations.

Additional fatigue requirements for design of risers are given in 3-7/9.

13 Out-of-roundnessOut-of-roundness is in this Guide defined as: (Dmax – Dmin)/D. Out-of-roundness may occur in themanufacturing phase, during transportation, storage installation and operation. Out-of-roundness mayaggravate local buckling or complicate pigging and is to be considered. If excessive cyclic loads isexpected during installation and operation, it is recommended that out-of-roundness due to through-life cyclic loads be simulated if applicable.



15 Allowable Stresses for Supports and RestraintsMaximum allowable shear and bearing stresses in structural supports and restraints are to followapplicable ABS Rules, AISC ASD Manual of Steel Construction, API RP 2A-WSD or alternativelyrecognized rules or standards.

17 Installation

During installation when the pipe is fully supported on the lay vessel, relaxed criteria in form ofmaximum allowable strain, e.g., may be applied when documentation for the criteria is submitted andapproved by the bureau.



S E C T I O N 5 Pipeline Rectification andIntervention Design


3 In-place Analysis ................................................................... 99

3.1 Parameters and Procedures for In-place Analysis................. 99

3.3 Modal Analysis ..................................................................... 100

3.5 Location Fixity....................................................................... 100

3.7 High Pressure/High Temperature......................................... 100

5 On-bottom Stability ............................................................. 101

5.1 Static Stability Criteria .......................................................... 101

5.3 Dynamic Stability Analysis ................................................... 101

7 Free Spanning Pipeline....................................................... 102

7.1 Evaluation of Free Spanning Pipelines ................................ 102

9 Upheaval and Lateral Buckling........................................... 103

9.1 Upheaval Buckling................................................................ 103

9.3 Lateral Buckling.................................................................... 104

11 Design for Impact Loads..................................................... 104

11.1 Fishing Gear Loads .............................................................. 104

11.3 Dropped Objects .................................................................. 104

11.5 Anchoring ............................................................................. 104



S E C T I O N 5 Pipeline Rectification andIntervention Design

1 General

This Chapter covers on-bottom stability and global buckling requirements for seabed interventiondesign related to pipes. The basic seabed intervention design may be performed using simple designequations, while more challenging design scenarios often will require a more advanced approach,such as the finite element method.

3 In-place AnalysisThe in-place model is to be able to analyze the in-situ behavior of a pipeline or riser over the through-life load history. The through-life load history consists of several sequential load cases, such as:

Installation;

Testing (water filling and system pressure test);

Operation (content filling, design pressure, and temperature);

Shut down and cool down cycles;

Storage.

3.1 Parameters and Procedures for In-place Analysis

When performing in-place analyses, static and dynamic loads are to be applied as applicable.

3.1.1 Static Analysis Procedure

Static analyses are to be performed when applicable to handle non-linearity from large-displacement effects, material non-linearity, and boundary non-linearity such as contact,sliding, and friction (pipe/seabed interaction).

3.1.2 Dynamic Analysis Procedure

Dynamic analyses may be used in the study of non-linear dynamic responses of pipes.General non-linear dynamic analysis uses implicit integration of the entire model to calculatethe transient dynamic response of the system. Implicit time integration is to be applied wherea set of simultaneous non-linear dynamic equilibrium equations is to be solved at each timeincrement.

Chapter 3 DesignSection 5 Pipeline Rectification and Intervention Design 3-5


When applicable, geometrical non-linearity is to be accounted for in the model. The instantaneous(deformed) state of the structure is to be updated through the analysis. This is especially importantwhen performing dynamic analysis of pipes subjected to wave loading. By including geometrical non-linearity in the calculation, a finite element program will use the instantaneous coordinates (instead ofthe initial) of the load integration points on the pipe elements when calculating water particle velocityand acceleration. This ensures that even if some parts of the pipeline undergo extreme lateraldisplacements, the correct drag and inertia forces will be calculated on each of the individual pipeelements that make up the pipeline.

3.3 Modal Analysis

The aim of the modal analysis is to calculate the natural frequencies and corresponding mode shapes.

In order to obtain natural frequencies, modal shapes and associated normalized stress ranges for thepossible modes of vibrations, a dedicated finite element program is to be used, and as a minimum, thefollowing aspects are to be considered:

3.3.1

Flexural behavior of the pipeline is modeled considering the bending stiffness and the effectof axial force.

3.3.2

Effective axial force that governs the bending behavior of the span is to be taken into account.

3.3.3

Interaction between a spanning pipe section and pipe lying on the seabed adjacent to the spanis to be considered.

Due consideration to points 3-5/3.3.1 and 3-5/3.3.2 above is to be given in both single span andmultiple-span modal analyses.

The axial effective force, i.e. the sum of the external forces acting on the pipe is also to be accountedfor. It is noted that the effective force may changes considerably during the various phases of thedesign life.

It is important to ensure that a realistic load history is modeled prior to performing the modalanalyses.

3.5 Location Fixity

The pipeline is to be designed with a specified tolerance of movement from its as-installed position.An analysis to determine that the anchoring arrangements, soil strength and friction coefficient willlimit the pipeline movement to the specified tolerance is to be performed.

The types of pipeline movements to be considered include: horizontal movement caused by currentand wave forces, vertical movement caused by hydrodynamic lift on the pipeline, and either positiveor negative vertical movements caused by loss of strength of the supporting or overburden soil, andearthquake-induced effects.

3.7 High Pressure/High Temperature

Design of high pressure/high temperature pipes is to consider global buckling due to thermal andinternal pressure induced expansion.



5 On-bottom StabilityUnless accounted for in the design, pipelines and risers resting on the seabed, trenched or buried arenot to move from their as-installed position under even extreme environmental loads. The lateralstability of pipelines and risers may in design be assessed using two-dimensional static or three-dimensional dynamic analysis methods.

The submerged weight of the pipe is to be established based on the on-bottom stability calculations,which will have a direct impact on the required pipe-lay tensions, installation stresses and pipeconfiguration on the sea-bottom.

Properly performed stability analysis performed in accordance with e.g. AGA L51698 will in generalbe acceptable to the Bureau.

5.1 Static Stability Criteria

Lateral stability criteria employ a simplified stability analysis based on a quasi-static balance of forcesacting on the pipe. The lateral stability analysis method may be defined as below:

γ(FD – Fi) ≤ µ(Wsub – FL)

where

FD = hydrodynamic drag force per unit length.

Fi = hydrodynamic inertia force per unit length.

FL = hydrodynamic lift force per unit length.

Wsub = submerged pipe weight per unit length.

µ = lateral solid friction coefficient.

γ = usage factor, equal to or larger than 1.1.

The effect of seabed contours is, if applicable, to be included in the analysis.

Buried pipes are to have adequate safety against sinking or floatation. Sinking is to be checkedassuming that the pipe is water filled, and floatation is to be checked assuming that the pipe is gas orair filled. If the pipe is installed in soils having low shear strength, the soil bearing capacity is to beevaluated.

Axial stability due to thermal and pressure effects is to be checked through simplified methods or adetailed in-place analysis. The axial stability criteria may be defined as those for lateral stabilitycriteria. The anodes are to be acceptable to sustain the anticipated axial friction force. Axial stability isto be evaluated using suitable soil/pipe interaction models.

For weight calculations of corroded pipelines, the expected average weight reduction due to metal lossis to be deducted. Reduction of soil shear strength, e.g. due to hydrodynamic loads, is to be consideredin the on-bottom stability design.

5.3 Dynamic Stability Analysis

Dynamic analysis involves full dynamic simulation of the pipeline resting on the seabed, includingmodeling of soil resistance, hydrodynamic forces, boundary conditions and dynamic response. It maybe used for detailed analysis of critical areas along a pipeline, such as pipeline crossings, riserconnections etc., where a high level of detail is required.

The acceptance criteria for dynamic analysis are defined based on strength criteria, deterioration/wearof coating, geometrical limitations of supports and distance from other structures etc.



The allowable lateral displacement of pipelines and risers is to be based on factors such as:

Distance from platform or other constraint;

Seabed obstructions;

Width of surveyed corridor;

Significant damage to external coating or anodes due to movement;

Interference with other pipelines or sub-sea installations due to movement;

Change in load condition due to movement;

Change in seabed features in adjacent areas.

7 Free Spanning PipelineThis Section gives acceptance criteria for vortex induced vibrations of free spanning pipes anddescribe a methodology applicable for design of pipeline systems.

Onset of cross-flow and in-line vortex induced vibrations is to be avoided unless it is demonstratedthat the allowable fatigue damage is not exceeded. Spans that are found critical with respect to vortexinduced vibrations may be corrected by creating intermediate supports in order to shorten the spanlength.

Design criteria applicable to different environmental conditions may be defined as follows:

i) Peak stresses or strain under extreme loading conditions are to satisfy the strength criteriagiven in Chapter 3, Section 4.

ii) Cyclic stress ranges smaller than the cut-off stress may be ignored in fatigue analyses.

iii) The allowable fatigue damage, see 3-4/11, is not to be exceeded.

7.1 Evaluation of Free Spanning Pipelines

When applicable, single span analysis is to be performed in order to assess the onset of in-line andcross-flow vortex induced vibrations, as well as to calculate fatigue damage.

A modal analysis of a single span with appropriate boundary conditions may be conducted tocalculate the natural frequency and modes for vortex induced vibration assessment. Differentboundary conditions are to be analyzed together with a range of axial forces.

For simplified analysis, the natural frequency of the span may be calculated as:

M

EI

L

Kf n 2

=

where

fn = natural frequency, in cycles per second.

I = moment of inertia of pipe

K = end-fixity condition constant

L = span length

M = approximate mass of pipe plus mass of water displaced by pipe

Span limitation due to vortex shedding is to consider the change in natural frequency due to thecombined effect of axial force and stiffness.



A multiple span analysis may be conducted to take into account the interaction between adjacentvertical spans, i.e. several spans may respond as a system. The multiple span approach may benecessary for the vertical mode of vibration where the seabed between adjacent spans form a fixedpoint about which the pipeline pivots during the vibration. Alternative methods, such as finite elementanalysis, can be employed to accurately estimate structural response due to vortex shedding.

The reduced velocity for vortex-shedding vibrations may be calculated as:

Df

UV

n

maxR =

where

D = outside diameter of pipe

Umax = maximum velocity determined based on a given return period

Based on the reduced velocity, onset of vortex induced vibrations is to be checked for the variousdesign conditions (installation, water-filled and operation). Those with the potential of experiencingsignificant cross-flow vortex induced vibrations are identified and measures to prevent or limit fatigueof the pipe are to be evaluated on a case-by-case basis.

For pipes installed in shallow waters, wave-induced in-line fatigue is to be evaluated. The in-linemotion for a free spanning pipe subjected to wave forces represented by the Morison force, dampingforces and axial forces may be determined using non-linear partial differential equations. The pipemotion as a function of time and position may be obtained by solving the equation of in-line motionusing modal analysis.

9 Upheaval and Lateral BucklingPressure and temperature from flow contents may cause expansion in the pipe length and the pipemay buckle to a new equilibrium position. Examples of expansion are:

Vertical downwards in a free span, up-lift on a free span shoulder and upheaval buckling forburied lines;

Horizontal snaking and/or lateral buckling on the seabed.

The following may accelerate global buckling:

Uneven seabed;

Local reduction in friction resistance;

Fishing gear impact, pull-over and hooking loads;

Out-of-straightness.

Pipes under internal/external pressure and seabed friction may be modeled as compressive beam-columns subject to an “effective force”. The seabed friction factors are to be properly modeled in theanalysis.

9.1 Upheaval Buckling

In case of an upheaval buckling resulting in limited plastic bending strains, pipelines and risers maycontinue operating, provided that the operating parameters are kept within a range that prevents theaccumulation of low-cycle high strain fatigue damage in the buckled section. When applicable, localbuckling, out-of-roundness and fatigue damage analyses are to be conducted and submitted forapproval by the Bureau.



9.3 Lateral Buckling

Allowing lateral buckling may be an effective way of designing high pressure/high temperaturepipelines and risers. In such situations, cyclic and dynamic behavior of the pipes is to be documentedthrough simulation of in-situ behavior. When applicable, local buckling, out-of-roundness and fatiguedamage analyses are to be conducted and submitted for approval by the Bureau.

11 Design for Impact LoadsFor unburied pipelines and buried pipelines where scour conditions could remove the overburden,accidental impact loading from such activities as anchoring, fishing operations, etc., is to beconsidered. The energy absorption properties of the pipeline are to be determined and correlated withthe probable accidental loading.

Risers are to be adequately protected from collisions with floating installation. The riser is to haveadequate strength to withstand impact loads caused by floating debris or ice, where applicable.

Pipeline and riser design is to consider impact loads such as:

Fishing gear impact, pull-over and hooking loads (when applicable);

Dropped objects;

Anchoring.

11.1 Fishing Gear Loads

When it is necessary to design for fishing gear loads, the weight, sizing (length and breadth) of thefishing gear and trawl velocity for the route where pipelines are to be installed are to be investigatedto form a design basis. Due consideration is to be given to the future developments or changes inequipment within the lifetime of the pipelines and risers.

11.3 Dropped Objects

Design for dropped objects is to be conducted accounting for falling frequency, weight and velocity ofthe dropped objects. The methods of analysis and acceptance criteria may be similar to those definedfor fishing gear impact.

11.5 Anchoring

Design for anchoring is to be conducted accounting for falling frequency, weight and velocity of thedropped objects. The methods of analysis and acceptance criteria may be similar to those defined forfishing gear hooking loads.



S E C T I O N 6 Routing, Installation, Constructionand Testing

CONTENTS1 Route Selection ................................................................... 107

1.1 Route Survey........................................................................ 107

3 Installation Analysis............................................................ 108

3.1 S-Lay Installation.................................................................. 109

3.3 J-Lay Installation................................................................... 109

3.5 Reel Lay Installation ............................................................. 109

3.7 Installation by Towing........................................................... 109

3.9 Installation of Risers ............................................................. 109

5 Construction ........................................................................ 110

5.1 Construction Procedures...................................................... 110

5.3 Trenching.............................................................................. 110

5.5 Gravel Dumping.................................................................... 110

5.7 Pipeline Cover ...................................................................... 110

5.9 Pipeline Crossings................................................................ 111

5.11 Protection of Valves and Manifolds...................................... 111

5.13 Shore Pull ............................................................................. 111

5.15 Tie-in..................................................................................... 111

7 System Pressure Testing and Preparation forOperation ............................................................................. 111

7.1 Testing of Short Sections of Pipe and FabricatedComponents ......................................................................... 111

7.3 Testing After New Construction............................................ 111

7.5 System Pressure Testing ..................................................... 112



S E C T I O N 6 Routing, Installation, Constructionand Testing

1 Route Selection

When selecting the pipeline route, consideration is to be given to the safety of all parties,environmental protection, and the likelihood of damage to the pipe or other facilities. Any futureactivities in the immediate region of the pipeline are to be accounted for when selecting the route.

In selecting a satisfactory route for an offshore pipeline, a field hazards survey may be performed toidentify potential hazards such as sunken vessels, pilings, wells, geologic and manmade structures,and other pipelines. Appropriate regulations are to be applied for minimum requirements forconducting hazard surveys.

The selection of the route is to account for applicable installation methods and is to minimize theresulting in-place stresses. Special route surveys may be required at landfalls to determine:

Environmental conditions caused by adjacent coastal features;

Location of the landfall to facilitate installation;

Location to minimize environmental impact.

1.1 Route Survey

The route survey covers survey for design purposes, survey for pre-installation and as-laid survey.The route survey is specified for pipelines mainly, but may also be applicable for risers. Issues relatedto the seabed intervention are discussed in Chapter 3, Section 5, “Seabed Intervention Design”.

1.1.1 Route Survey for Design

A detailed route survey is to be performed for the planned pipeline route to provide sufficientdata for the design. The width of the survey corridor is to be wide enough to cover theinstallation tolerance. Detailed and more accurate surveys are required, especially for unevenseabed topography, obstructions, near installations or templates, existing pipeline or cablecrossings, sub-surface conditions, large boulders, etc.

Seabed bathymetry and soil data properties are to be investigated and provided based on theroute survey results. Seabed properties, including different soil layers, are to be included inthe route survey maps. As a minimum, the soil stiffness and seabed soil friction coefficients inboth axial and lateral directions are to be provided.

Chapter 3 DesignSection 6 Routing, Installation, Construction and Testing 3-6


1.1.2 Route Survey for Pre-Installation

Prior to installation, the route is to be surveyed for the following cases:

New installations along the route;

Changes of installation (e.g. templates) location;

Change of seabed conditions due to heavy marine activities;

New requirements due to seabed intervention design or installation engineering

1.1.3 As-Laid Survey

After installation, an as-laid survey is to be conducted. As a minimum, the following is to beincluded in the as-laid survey:

Position (coordinates) and water depth profile for the pipeline or riser systems;

Coordinates identifying starting and ending point;

Identification and quantification of any spans, crossings, structures and largeobstructions;

Reporting of any damages to the pipeline or riser systems including pipes, cathodicprotection system, weight coating, supports, appurtenances, in-line structures, etc.

If necessary, the integrity assessment of the pipeline and riser system based on as-laid surveyis to be performed.

1.1.5 As-Built Survey

After the final testing of the pipeline or riser system, an as-built survey is to be conducted.This survey may be limited to key locations defined during the As-laid survey such asidentified spans, crossings, subsea structures and areas with special features. As a minimum,the following is to be included in the as-built survey:

Positions (coordinates) and water depth profile including tangential points, out-of-straightness measures, etc.;

Quantification of spans, crossings, trench, burial, scour, erosion;

Reporting of any damages to the pipeline or riser systems including pipes, cathodicprotection system, weight coating, supports, appurtenances, in-line structures, etc.

3 Installation Analysis

An analysis of the pipe-laying operation is to be performed taking into account the geometricalrestraints of the anticipated laying method and lay vessel, as well as the most unfavorableenvironmental condition under which laying will proceed. The analysis is to include conditions ofstarting and terminating the operation, normal laying, abandonment and retrieval operation, andpipeline burial. The analysis is to ensure that excessive strain, fracture, local buckling, or damage tocoatings will not occur under the conditions anticipated during the pipe-laying operation.

Strength analysis is to be performed for the pipeline during laying and burial operations and for theriser during installation. The strength analysis is to account for the combined action of the appliedtension, external pressure, bending and dynamic stresses due to laying motions, when applicable.



3.1 S-Lay Installation

For S-lay installation, the pipe is laid from a near-horizontal position using a combination ofhorizontal tensioner and a stinger controlling the curvature at over-bend. The lay-vessel can be a ship,barge or a semi-submersible vessel. The required lay tension is to be determined based on the waterdepth, the submerged weight of the pipeline, the allowable radius of curvature at over-bend, departureangle and the allowable curvature at the sag-bend. The stinger limitations for minimum and maximumradius of curvature and the pipeline departure angle are to be satisfied.

Strain concentrations due to increased stiffness of in-line valves are to be accounted for. The in-linevalve is to be designed for strength and leakage protection to ensure the integrity of the in-line valveafter installation.

Due to local increased stiffness by e.g. external coatings and buckle arrestors, strain in girth weldsmay be higher than in the rest of the pipe and strain concentration factors are to be calculated based onstrain level and coating thickness or wall-thickness of buckle arrestors.

Installation procedures are to safeguard the pipe with coatings, protection system, valves and otherfeatures that may be attached. Criteria for handling the pipe during installation is to consider theinstallation technique, minimum pipe-bending radii, differential pressure, and pipe tension.

3.3 J-Lay Installation

For J-Lay (Near-vertical pipe-lay), the pipe is laid from an elevated tower on a lay vessel usinglongitudinal tensioner. In this way over-bend at the sea surface is avoided. In general, J-Lay followsthe same procedure as S-Lay (see 3-6/3.1).

3.5 Reel Lay Installation

For reel lay, the pipe is spooled onto a large radius reel aboard a reel lay vessel. The reel-off atlocation will normally occur under tension and involve pipe straightening through reverse bending onthe lay vessel. The straightener is to be qualified to ensure that the specified straightness is achieved.

Anodes are in general to be installed after the pipe has passed through the straightener and tensioner.

Filler metals are to be selected to ensure that their properties after deformation and aging match thoseof the base material.

Fracture mechanics assessment may be conducted to assess ductile crack growth and potentialunstable fracture during laying and in service. The allowable maximum size of weld defects may bedetermined based on fracture mechanics and plastic collapse analysis.

3.7 Installation by Towing

The pipe is transported from a remote assembly location to the installation site by towing either on thewater surface, at a controlled depth below the surface or on the sea bottom.

The submerged weight of the towed pipeline (e.g. bundles) is to be designed to maintain controlduring tow. The bundles may be designed to have sufficient buoyancy by encasing the bundledpipelines, control lines and umbilical inside a carrier pipe. Ballast chains may be attached to thecarrier pipe at regular intervals along the pipeline length to overcome the buoyancy and provide thedesired submerged weight.

3.9 Installation of Risers

Installation conditions regarding sea-state and current are to be specified to avoid any over-stressingof the pipe and joints. Contingency procedures are to be specified to cover dynamic positioningsystem breakdown, anchor dragging and anchor line failure. Safety of subsea operation is to meet therequirements of the National Authorities.



Requirements for riser installation, e.g. welding and non-destructive testing, are similar to thosedescribed for pipelines.

Upon completion of installation, remotely operated vehicles or diver survey is to be conducted toconfirm the position of the riser relative to the platform and expansion loops.

5 ConstructionPipelines and risers are to be constructed in accordance with written specifications that are consistentwith this Guide. The lay methods described in 3-6/3 and other construction techniques are acceptableprovided the pipeline meets all the criteria defined in this Guide. Plans and specifications are to beprepared to describe alignment of the pipeline, its design water depth, and trenching depth and otherparameters.

5.1 Construction Procedures

The installation system is to be designed, implemented, and monitored to ensure the integrity of thepipeline system. A written construction procedure is to be prepared, including the following basicinstallation variables:

Water depth during normal lay operations and contingency situations;

Pipe tension;

Pipe departure angle;

Retrieval;

Termination activities.

The construction procedure is to reflect the allowable limits of normal installation operations andcontingency situation.

5.3 Trenching

Where trench excavation and mechanical back filling are applied, pipeline, coating and equipment areto be installed, operated, and removed to prevent damaging.

The standard depth of trenching for pipelines is the depth that will provide 3 feet (0.9 meter) ofelevation differential between the top of the pipe and the average sea bottom. The hazards are to beevaluated to determine the total depth of trenching in those situations where additional protection isnecessary or mandated.

A post-trenching survey is to be conducted to determine if the required depth has been achieved.

5.5 Gravel Dumping

Gravel dumping is to be controlled such that the required gravel is dumped over and under thepipeline and sub-sea structures and over the adjacent seabed. During the gravel dumping operations,inspection is to be carried out to determine the performance of the dumping. Upon completion of thegravel dumping, a survey is to be conducted to confirm the compliance with the specifiedrequirements.

5.7 Pipeline Cover

Pipeline cover is normally installed where more protection is required. Pipeline and coating are to beprotected from damage in areas where backfill is specified, or where pipeline-padding material isspecified.



5.9 Pipeline Crossings

Pipeline crossings are to comply with the design, notification, installation, inspection, and as-builtrequirements of the regulatory agencies and the owners or operators of the pipelines involved.

5.11 Protection of Valves and Manifolds

Valves, manifolds, and other sub-sea structures installed on an offshore pipeline are to be protectedfrom fishing gear and anchor lines. Protective measures are to be applied to prevent damage to thevalves and manifolds. Such measures are not to obstruct trawling or other offshore operations.

5.13 Shore Pull

Shore Pull is a process in which a pipe string is pulled either from a vessel to shore or vice versa.Installation procedures are to be prepared including installation of pulling head, tension control,twisting control and other applicable items.

Cables and pulling heads are to be dimensioned for the loads to be applied, accounting foroverloading, friction and dynamic effects. Winches are to have adequate pulling force, and are to beequipped with wire tension and length indicators.

5.15 Tie-in

Tie-in procedures are to be prepared for the lifting of the pipeline/riser section, control ofconfiguration and alignment, as well as mechanical connector installation. Alignment and position ofthe tie-in ends are to be within specified tolerances prior to the tie-in operation.

7 System Pressure Testing and Preparation for OperationSystem pressure test is to be performed on the completed system and on all components not testedwith the pipeline system or components requiring a higher test pressure than the remainder of thepipeline. If leaks occur during tests, the leaking pipeline section or component is to be repaired orreplaced and re-tested in accordance with this Guide.

7.1 Testing of Short Sections of Pipe and Fabricated Components

Short sections of pipe and fabricated components such as risers, scraper traps, and manifolds may betested separately from the pipeline. Where separate tests are used, these components are to be tested topressures equal to or greater than those used to test the pipeline/riser system.

7.3 Testing After New Construction

7.3.1 Testing of Systems or Parts of Systems

Pipelines and risers designed according to this Guide are to be system pressure tested aftercompletion of trenching, gravel dumping, covering and crossing.

It is to be ensured that excessive pressure is not applied to valves, fittings, and otherequipment. The valve position and any differential pressure across the valve seat are to bespecifically defined in the test procedures.

7.3.2 Testing of Tie-ins

Sometimes it is necessary to divide a pipeline system into test sections and install weld caps,connecting piping, and other test appurtenances. Tie-in welds that have not been subjected toa pressure test are to be radiographically inspected. After weld inspection, field joints are tobe coated and inspected. Mechanical coupling devices used for tie-in are to be installed andtested in accordance with the manufacturer’s recommendations.



7.5 System Pressure Testing

7.5.1 Test-Pressure Levels

All parts of an offshore pipeline or riser designed according to this Guide are to be subjectedto a post-construction test. An appropriate pressure level is to be defined and approved by theBureau. The system pressure test is not to result in hoop stress and combined stress exceedingthe capacity given in Chapter 3, Section 4.

7.5.2 Test-Medium Considerations

The test medium is to be fresh water or seawater. Corrosion inhibitor and biocide additivesare to be added to the test medium in case the water is to remain in the pipeline for anextended period.

If use of water is impractical, however, air or gas may be used as test medium, provided that afailure or rupture would not endanger personnel.

Precautions are to be taken to prevent the development of an explosive mixture of air andhydrocarbons.

Effects of temperature changes are to be taken into account when interpretations are made ofrecorded test pressures.

Plans for the disposal of test medium together with discharge permits may be requiredsubmitted to the Bureau.

7.5.3 Duration of System Pressure Tests

Test pressure is to be maintained above the minimum required test pressure for a minimum of8 hours. The duration of the system pressure test may be of 4 hours for fabricated componentsand short sections of pipe where visual inspection has been conducted to verify that there isno leakage.



S E C T I O N 7 Special Considerations for Designof Metallic Risers

CONTENTS1 Scope and Objectives ......................................................... 115

3 Descriptions of Riser System............................................. 115

5 Design Conditions and Loads ............................................ 116

7 Design Criteria..................................................................... 116

9 Global Response Analysis.................................................. 116

9.1 Analysis Methodology and Procedure.................................. 116

9.3 System Modeling.................................................................. 117

9.5 Static and Dynamic Analysis ................................................ 117

9.7 Fatigue.................................................................................. 118

9.9 Fatigue due to Vortex Induced Vibrations ............................ 119

9.11 First Order Wave Loading Induced Fatigue ......................... 119

9.13 Low Frequent Fatigue Induced by Motion of FloatingInstallation ............................................................................ 120

9.15 Other Fatigue Causes .......................................................... 120

11 Riser Components Design.................................................. 120

11.1 Tapered Stress Joints .......................................................... 120

11.3 Flexible Joints....................................................................... 120

11.5 Bend Stiffener....................................................................... 120

11.7 Helical Strakes ..................................................................... 121

11.9 Buoyancy Modules ............................................................... 121

11.11 Riser Support Systems......................................................... 121

11.13 Collision of Risers................................................................. 121



S E C T I O N 7 Special Considerations for Designof Metallic Risers

1 Scope and Objectives

Rigid metallic risers are to be evaluated using the design criteria specified in the previous Chapterstogether with the additional requirements for design procedure, acceptance criteria, componentselections, configuration and installation methods addressed in this Chapter.

3 Descriptions of Riser SystemA riser system essentially consists of pipes connecting a fixed or floating installation with pipelinesand wellheads at the seabed.

The riser configuration design is to be performed according to production requirements and sitespecifications and are to satisfy the following basic requirements:

Global behavior and geometry;

Structural integrity, rigidity and continuity;

Material properties;

Means of support.

Riser systems are to be arranged so that the external loading is kept within acceptable limits withregard to the strength criteria described in Chapter 3, Section 4.

Initial riser configuration can be developed based on the minimum wall thickness determined fromChapter 3, Section 4 based on suspended lengths and given top angle. Initial configurationdevelopment can be conducted using dynamic analyses for extreme storm conditions.

Apart from the basic pipe structures, the ancillary components used in riser systems are to beevaluated. The ancillary components of a riser system are to be able to withstand high tension,bending moments and fatigue. Examples of ancillary components are threaded joints, flexible joints,buoyancy modules, end fittings, etc.

Chapter 3 DesignSection 7 Special Considerations for Design of Metallic Risers 3-7


5 Design Conditions and Loads

In general, the loads to be applied to risers follow the description given in Chapter 3, Sections 1 to 5.

For riser systems linked to a floating installation, the installation motion due to environmental loads(wave, wind and current) will influence the riser system through the top connection. Floatinginstallation response amplitude operators, which relate wave surface elevation amplitude, floatinginstallation response amplitude and the phase lag are to be used for wave frequency motions.

Floating installation horizontal (static) offset and low frequency motion corresponding to the meanoffset due to wind, wave and current acting on the installation are to be considered for normal andextreme conditions and may be based on e.g. API RP 2SK and API RP 2T.

As a basic, the riser analysis is to consider the following:

Floating installation at the neutral, far, near and transverse positions;

Loss of station-keeping ability due to mooring line or tendon failure, floating installation tiltdue to damage or dynamic position failure (drive-off or drift-off), etc.;

Partial loss of riser tension or buoyancy.

7 Design CriteriaAdditional acceptance criteria such as stated in API RP 2RD are to be considered for risers in additionto those referenced in Chapter 3, Section 4.

9 Global Response AnalysisFor risers attached to floating installations, special considerations are to be given to hydrodynamicresponse, touch down point and vortex induced vibration analysis. Riser response is highly nonlinearand an interactive design approach is to be adopted to balance extreme storm and fatigue designrequirements.

The purpose of riser global response analysis is to verify the design, indicate the operating limits, andprovide load effects distribution along the riser length for strength checks. Global analysis is to beperformed for a wide range of environmental and operational conditions. In addition, the analysis is toindicate the operating limits.

9.1 Analysis Methodology and Procedure

Detailed analysis models are to include geometry model, environmental model, pipe-soil interactionmodel and coupling model with the floating installation. Both static and dynamic responses of theriser are to be performed. Detailed analysis is to be conducted in areas of high loading/stress, such astouch down point and at the interface with the floating installation.

The relevant static configuration is to be applied as the initial condition for a time-domain analysis.Initial static runs are conducted to evaluate the riser configuration covering the range of currentprofiles and extreme offset positions of the floating installation. Where satisfactory arrangements areachieved, a time-domain dynamic analysis is to be conducted using the appropriate design waves.Particular attention is to be given to specification and definition of motions and phase angle for thefloating installations. Checks are to be conducted to confirm sign conventions and specification ofriser position related to the floating installation response amplitude operator’s reference. In addition,the number of modeled loading cycles beyond the initial loading ramp is to be checked to ensure thatthe analysis has reached a stable solution. Particular attention is to be given to high stress locationssuch as the touch down point. Analysis time steps are to be selected to produce acceptable resolutionof time trace outputs



9.3 System Modeling

System modeling is to model the system geometry, material, mass, environmental conditions,boundary conditions, structural damping and stiffness properties and is to establish an adequatemathematical model for static and dynamic analysis of risers. It is important to select a proper modelfor a given application.

9.3.1 Geometry and material models

To describe the geometry properly, a detailed geometry model is needed to include the majorcomponents (e.g. taper stress joints, J-tube contact). Imperfections such as out-of-roundnessand corrosion defects are to be included in the geometry model. To model the bendingstiffness of the riser system properly, additional components such as auxiliary pipes, variedwall thickness, large appurtenances (attached equipment) are needed to be considered in theglobal stiffness. The established model is to be able to estimate interface load effects as inputfor the design check of relevant equipment.

9.3.2 Load models

In principle, internal and external pressure and functional loads can be modeled as static.Environmental loads, floating installation motions and accidental loads like dropped objectsare in general to be modeled using dynamic analysis.

9.3.3 Wave model

Due to the random nature of waves, the sea state is generally represented by statisticaldescriptions such as significant wave height, spectral peak period, average wave period,spectral shape and directionality. The occurrence of significant wave height is generallydescribed by a wave scatter diagram, which provides the total number of wave counts forfatigue analysis purposes.

9.3.4 Current model

The current velocity profile can be modeled as time independent for each sea state. Generally,current can be modeled by superimposing a stepwise linear current profile in the samedirection as the wave.

9.3.5 Inertia models

The inertia of risers may be adequately modeled using a lumped mass matrix for a reasonablediscretization.

9.3.6 Riser-Seabed interaction models

A proper model for riser and seabed interaction is needed especially to perform an adequateanalysis of touch down point.

9.5 Static and Dynamic Analysis

Typical global response analysis of a riser system includes static analysis, eigen-value analysis anddynamic analysis. The following presents the basic methods and procedure for riser global responseanalysis. The objective is to provide general guidance on analysis techniques and modeling practicetypically applicable in the design and analysis of risers. The key issues that need to be properlyaddressed in riser analysis are covered, including effective tension, stiffness, mass, buoyancy andhydrodynamic loads.

9.5.1 Static Analysis

As the first step in riser global response analysis, the static analysis is to establish the staticequilibrium configuration due to static loads acting on the riser system.



Static forces acting on the riser includes:

Axial force and shear force;

Horizontal forces due to the resultant of external and internal hydrostatic pressures;

Vertical force due to the resultant of external and internal hydrostatic pressure;

Drag forces due to steady current and wave;

The weight of the element acting vertically downwards;

Mean offset of floating installation.

9.5.2 Eigen-value analysis

Eigen-value analysis is to be performed to estimate eigen-frequencies and eigen-modes of theriser system, which will be required for e.g. vortex induced vibration analysis.

9.5.3 Dynamic analysis

Frequency domain analysis is appropriate when the effects of tension coupling are known tobe small, and there is no other non-linearity. Frequency domain analysis is often used forfatigue analysis with the objective of obtaining estimates of root-mean-square and axial andbending stresses. Frequency domain analysis is also useful to estimate root-mean-squarestresses for use in strength calculations of certain components as well as estimating clearancebetween risers.

Wave and current forces modeled by Morison’s equation are nonlinear in velocity, but can besuccessfully linearized. The solution to the linearized dynamic motion response equation is interms of displacement amplitude and phases as functions of frequency, linearized to aparticular sea-state.

When displacement amplitudes divided by the wave amplitudes are used to generate theloads, the results are termed frequency response functions or transfer functions. The transferfunctions can then be used to generate response estimated for a variety of environmentalconditions.

In addition to properly linearizing the drag force, careful selection of analysis frequencies isessential to adequately model riser response. Frequencies used in the analysis are to result inadequate definition of the wave energy spectrum, characteristics of floating installationresponse and natural frequencies of the riser.

Nonlinear effects encountered in some riser analysis can be directly modeled in the timedomain. In addition, time domain analysis may be used to analyze transient events. Finally,time domain analysis can be used to assess the relative accuracy of equivalent frequencydomain analysis and calibrate them for use in the design.

Estimation of large displacement and large rotation behavior of riser systems usually requirednonlinear time domain simulations. However, for some cases, linearized time domainsimulation can be adopted to save computational efforts.

9.7 Fatigue

Riser components may exceed fatigue limit damage, see 3/4.6, due to fluctuations in operationalconditions such as temperature and pressure and due to cyclic environmentally induced loading andmotions. The environmental loading and motions can generally be divided into:

Wave and current vortex induced vibrations;

1st order wave loading and associated motion of the floating installation;

2nd order motion of the floating installation.



In addition to the above causes of fatigue, fatigue analyses are to include all expected cyclic loadsimposed on the riser large enough to cause fatigue damage. The expected loads are to be quantified inform of both magnitude and number of cycles.

Fatigue may be assessed by recognized analytical methods in conjunction with laboratory testing ofcomponents.

9.9 Fatigue due to Vortex Induced Vibrations

Vortex induced vibrations may be generated by waves or currents and can be both in-line and normalto the direction of current flow. The most severe form of vortex induced vibrations, in terms of fatiguedamage, is cross-flow vibration due to steady current, but it is recommended that methods consideringthe sheared flow regime and interaction of vibration modes along the riser length be applied in thedesign.

9.9.1 Modeling approachThe definition of current velocity profile is an important factor. The current velocitycomponent normal to the pipe is to be calculated based on the angle variation along the pipeand the incident angle of the current. Consideration is also to be given to the damping effectof the seabed where seabed and pipe are in contact. For risers, the touch down point at theseabed may be modeled using a pinned end restraint.

9.9.2 Analytical approachAnalyses are first conducted assuming no suppression devices are attached to the pipe or riser.The vortex induced vibration fatigue damage of each profile analyzed is then factoredaccording to the frequency of occurrence of the profile and the total fatigue damage due tovortex induced vibrations is then given by the sum of the factored damage for each profile.Final analyses are conducted using the specified arrangement, which incorporates vortexinduced vibration suppression devices as required to achieve the desired fatigue life. Asdirectionality of current and riser orientation is not specified, analyses are conducted forcurrents flowing in the plane of the riser and normal to the riser. For application of thecurrents in the plane of the riser, the velocity profile is resolved normal to the nominal riserposition.

9.9.3 Fatigue damage summationFatigue damage from first order response due to individual sea-states and from vortex inducedvibrations generated by individual current profiles may be summed using Palmgren-Miner’srule. Consideration is to be given to the distribution of fatigue damage around the risercircumference in order to avoid unnecessary conservatism.

9.11 First Order Wave Loading Induced Fatigue

As a minimum, the wave climate is to be defined by an Hs-Tp (or Hs-Tz) scatter diagram. Theparameters, which define the sea-state spectra, is to be provided based on observed data. This maytake the form of Pierson-Moskovitz or JONSWAP single peak spectra or a bi-modal spectrum.Further definition of wave climate is to consist of a spreading parameter giving the directionaldistribution of the waves.

Riser fatigue damage may be found by assuming a one or two directional wave loading, but whereapplicable, a larger number of directional probabilities may be specified to avoid undue conservatismin the fatigue damage estimation.

A spectral fatigue analysis approach may be applied for first order fatigue analysis where the fatiguedamage is based on random sea analyses of riser response. The sea-states may be split into a numberof windows and one typical sea-state selected from each window. The fatigue damage resulting fromeach sea-state is then determined using the total stress transfer function obtained from the selectedsea-state. The damage from different sea-states is summed using Palmgren-Miner’s rule.



9.13 Low Frequent Fatigue Induced by Motion of Floating Installation

Low frequent motions of the floating installation may have a significant influence on riser touch downpoint fatigue damage and are to be accounted for. In addition, the slowly varying components of thedrift motion provide a further contribution to total riser fatigue damage. The approach to analysis oflow frequency induced fatigue may follow that used for first order fatigue analysis. For each sea-state,the mean drift offset and mean plus root-mean-square low frequency drift motion is to be considered.The scatter diagram may be split into windows, the sea-states in each having similar driftcharacteristics. The total fatigue damage from each window may then be found assuming the samedrift motions apply to each sea-state in the window. Within each scatter diagram window, the meanand root-mean-square drift offset are conservatively selected based on the extreme values of any ofthe sea-states in the window.

9.15 Other Fatigue Causes

The following causes are to be considered for fatigue evaluation as appropriate.

9.15.1 Shutdown and startup

Normal operational shutdown and start-up may introduce load cycles giving stress range forrisers. Stress ranges are calculated from stress variation between cold non-pressurized tonormal operating condition. Stress concentrations for welds are to be included in the stressranges calculation.

9.15.2 Effect of installation

The effects of reeled installation on riser welds are to be included in the fatigue lifeestimation.

9.15.3 Effect of floating installation

The hull flexure (springing) may have effect on the fatigue life of risers. This is to beconsidered by taking into account of springing numbers.

11 Riser Components Design

This section contains the design considerations for riser components that are commonly used in theriser system. There is a large variety of riser components such as riser segments, fluid conduitinterfaces, fluid control, insulation and components for stability and external load control.

11.1 Tapered Stress Joints

Tapered stress joints may be formed by varying the wall thickness of the pipe joint. The bendingstiffness of the tapered stress joint is a transmission from the more rigid section of the riser to theopposite less stiff riser section.

11.3 Flexible Joints

Flex-joint stiffness and dimensions are to be selected based on supplier design data. A sensitivitystudy is to be conducted to determine the effect of non-linear stiffness variations and effects ofinternal pressure and temperature variations on flex-joint stiffness and riser response.

11.5 Bend Stiffener

Bend stiffeners may be introduced to avoid large curvature caused by considerable deflections. Bendstiffeners are often made of a polymeric molded material surrounding the pipe and attached to the endfitting.



11.7 Helical Strakes

A helical strake is mainly used to alter the flow separation characteristics over the cross section of theriser as well as in the span-wise direction. Requirements for helical strakes are to be determined by aninteractive design process. In high current condition it is likely that a helical strake will be requiredalong a proportion of the riser length dependent on depth, diameter, tension and current profile.Where helical strake suppression is used, the impact of suppression devices on riser weight, dragdiameter and drag coefficients are to be correctly accounted for in accordance with recognized testdata. It is noted that a helical strake can lead to a significant increase of the drag and added masscoefficients.

11.9 Buoyancy Modules

Buoyancy modules are to have a material density appropriate for the application depth. The nominaldensity is to be selected to account for buoyancy fittings, such as straps and thrust plates whereapplicable. The effects of seawater absorption, hydrostatic compression, and buoyancy fabricationtolerances are to be considered.

11.11 Riser Support Systems

Riser support systems usually include the following components:

Dead weight support;

Riser guide;

Riser anchor support;

Riser flange and clamp.

The design of riser support structures based on relevant code, e.g. API RP 2A-WSD, is acceptable.The recommended design procedure of riser support systems is as follows:

Properly perform global structural analysis, including the riser support system;

Extract reaction forces and bending moments at support locations;

Transform the load effects from global analysis into local axes;

Select the worst load cases with highest load effects;

Design riser guide and deadweight support;

Design local support structures according to relevant structural design codes.

11.13 Collision of Risers

Collision of risers in parallel, especially for deepwater risers, may cause damage to the buoyancymodules, coating or the pipe itself. The riser system is to be designed in such a way that collision isavoided. Sufficient clearance between risers is to be guaranteed to avoid interference and damage.

The following is to be considered in determining the riser spacing:

Riser coordinates, geometric data, pretension at top and bottom;

Current velocity profile and direction;

Drag coefficient of the riser at specific water levels.

For deep waters, wave forces will act on a minor part of the riser, while most of its length will befound in depths where current will be the only source for hydrodynamic forces. Vortex inducedvibrations are expected to be an important design consideration.

Long risers can easily have large relative deflections that may lead to unacceptable collisions betweenrisers.



S E C T I O N 8 Special Considerations for Pipe inPipe Design

1 GeneralThis Chapter defines the design criteria that are specifically applied to pipe-in-pipe systems. Relevantfailure modes for pipelines, described in Chapter 3, Section 4, are to be considered in the design ofpipe-in-pipe systems.

3 Design Criteria

3.1 Strength Criteria

The design of pipe-in-pipe systems is in general to follow the strength criteria given in Chapter 3,Section 4. For high temperature/pressure systems, an equivalent strain criterion may be applied as:

)(/ prphpp22232 εεεε ++=

where

εp = Longitudinal plastic strain

εph = Plastic hoop strain

εpr = Radial plastic strain

The maximum allowable accumulation of plastic strain is to be based on refined fracture calculationsand is to be submitted for approval by the Bureau.

The inner pipe burst capacity of the pipe-in-pipe system is determined based on the internal pressure,and local buckling capacity is evaluated based on the outer pipe subjected to the full external pressure.

3.3 Global Buckling

In terms of structural behavior, a pipe-in-pipe system may be categorized as being either compliant ornon-compliant, depending on the method of load transfer between the inner and outer pipes. Incompliant systems, the load transfer between the inner and outer pipes is continuous along the lengthof the pipeline, and no relative displacement occurs between the pipes, whereas in non-compliantsystems force transfer occurs at discrete locations. Due to effective axial force and the presence ofout-of-straightness (vertically and horizontally) in the seabed profile, pipe-in-pipe systems aresubjected to global buckling, namely upheaval buckling and lateral buckling. In contrast to upheavalbuckling, lateral buckling may be accepted if it does not result in unacceptable stresses and strains. Incase global buckling may occur, a detailed finite element analysis is recommended to investigate thebuckling behavior further.



S E C T I O N 9 Special Considerations forPipeline Bundle Design

CONTENTS1 General................................................................................. 127

3 Functional Requirements.................................................... 127

3.1 Design Temperature/pressure.............................................. 127

3.3 Pigging Requirements .......................................................... 127

3.5 Settlement/embedment ........................................................ 127

3.7 System Thermal Requirements............................................ 127

5 Design Criteria for Bundle Systems................................... 128

5.1 Carrier Pipe Design .............................................................. 128

5.3 Wall Thickness Design Criteria ............................................ 128

5.5 On-Bottom Stability Design .................................................. 129

5.7 Free Spans Design............................................................... 129

5.9 Bundle Expansion Design .................................................... 129

5.11 Bundle Protection Design..................................................... 129

5.13 Corrosion Protection Design ................................................ 129

5.15 Bulkheads and Towhead Structure Design.......................... 129

5.17 Bundle Appurtenances Design............................................. 129



S E C T I O N 9 Special Considerations forPipeline Bundle Design

1 General

This Chapter defines the design criteria that are specifically applied to pipeline bundle systems.Relevant failure modes described in Chapter 3, Section 4, are to be considered in the design ofpipeline bundle system.

3 Functional RequirementsPipeline bundle systems may be used in applications where pipe insulation is required to avoidhydrate and wax formation. The product lines, umbilical and insulation are usually enclosed in asingle carrier pipe. The following functional requirements are to be considered:

3.1 Design Temperature/pressure

Design temperature and pressure are to be based on hydraulic analyses. Significant temperature dropsalong the bundle system are to be avoided.

3.3 Pigging Requirements

If the bundle system is designed for pigging, the geometric requirement is to be fulfilled. Theminimum bend radius is usually 5 times the nominal internal diameter of the pipe to be pigged.

3.5 Settlement/embedment

Settlement/embedment of the pipeline bundle system is to be taken into account where appropriate.

3.7 System Thermal Requirements

The insulation value is to be determined based on thermal conduction, convection and hydraulicanalysis considering:

Maximum/minimum operating temperature;

Cool down time;

Heat-up time;

Heat-up system volume;

Bundle configuration and the relative positions of the components;

Bundle length;

Chapter 3 DesignSection 9 Special Considerations for Pipeline Bundle Design 3-9


Heating medium temperature;

Heating medium flow rate;

Properties of the fluid contained inside the pipelines.

5 Design Criteria for Bundle SystemsThe design of bundle systems is to ensure that the system satisfies the functional requirements andadequate structural integrity is maintained against all the failure modes.

Design of the carrier pipelines, heat-up lines and service line is to be in accordance with Chapter 3,Section 4. The design criteria are to be applicable for installation, system pressure test and operation.

5.1 Carrier Pipe Design

Carrier pipe stresses are to be checked during the carrier selection and are to be reviewed in light ofthe stresses determined from the expansion analysis.

The weight of all the bundle component parts is to be determined. The displacement of externalanodes, clamps and valves is to be accounted for by using a submerged weight for these items in theweight calculations.

5.3 Wall Thickness Design Criteria

Pipelines are to be sized according to processing data. The wall thickness of the pipelines depends onthe internal pressure containment. For high temperature applications, thermal loading is to beconsidered in pipeline sizing and selection of material properties that will apply at elevatedtemperatures.

The wall thickness design of pipes within the bundle system is to take into account the following:

5.3.1 Hoop stress

The hoop stress criterion in Chapter 3, Section 4 is applicable for bundle systems.

5.3.2 Collapse due to external hydrostatic pressure

The wall thickness of the carrier pipe is to be designed to avoid pipe collapse due to externalhydrostatic pressure.

5.3.3 Local buckling

The pipelines, carrier and sleeve pipe are to be designed to withstand local buckling due to themost unfavorable combination of external pressure, axial force and bending.

5.3.4 Installation stress

The wall thickness is to be adequate to withstand both static and dynamic loads imposed byinstallation operations.

5.3.5 System pressure test and operational stresses

The wall thickness is to be adequate to ensure the integrity of carrier and sleeve pipe underthe action of all combinations of functional and environmental loads experienced duringsystem pressure test and operation.



5.5 On-Bottom Stability Design

The bundle system is to be stable on the seabed under all environmental conditions encounteredduring installation, testing and throughout the design life. The bundle is to be designed with sufficientsubmerged weight to maintain its installed position, or to limit movement such that the integrity of thebundle system is not adversely affected. The bundle may be considered stable when actual submergedweight is greater than the minimum required multiplied a factor of 1.1.

On-bottom stability is to be verified in accordance with 3-5/5.

5.7 Free Spans Design

Maximum allowable span length for the bundle system is to be calculated for both static and dynamicloading conditions. Analyses are to consider all phases of the bundle design life including installation,testing and operation.

5.9 Bundle Expansion Design

The design is to take into account expansion and/or contraction of the bundle as a result of pressureand/or temperature variation. The bundle expansion analysis includes determination of external andinternal forces acting on the system, calculation of axial strain of the system and integration of theaxial strain of unanchored bundle to determine the expansion. Design pressure and the maximumdesign temperature are to be used in bundle expansion analysis. The presence of the sleeve pipe is tobe taken into account. Bundle expansion movement is to be accommodated by the tie-in spools.

5.11 Bundle Protection Design

The bundle system is to be designed against impact loads in areas where fishing activities arefrequent. The pipelines and umbilicals are to be protected against dropped objects around theinstallations, see 3-5/7. Carrier pipe and bundle towheads are to offer sufficient protection against thedropped objects.

5.13 Corrosion Protection Design

Cathodic protection design is to be performed according to relevant codes, e.g. NACE RP0176.Cathodic protection together with an appropriate protective coating system is to be considered forprotection of the external steel surfaces from the effects of corrosion.

The sleeve pipe is to be protected from corrosion using chemical inhibitors within the carrier annulusfluid. Pipelines within the sleeve pipe are to be maintained in a dry environment, and a cathodicprotection system will therefore not be required.

5.15 Bulkheads and Towhead Structure Design

The bulkheads will form an integral part of the towhead assemblies. The towhead structure is toremain stable during all temporary and operational phases. Stability is to be addressed with respect tosliding and overturning with combinations of dead weight, maximum environmental and accidentalloads applied. The design of towhead structure is to be in accordance with relevant structural designcode.

5.17 Bundle Appurtenances Design

Design of bundle appurtenances is to be based on their functional requirements:

Spacer;

Filling, flood and vent valves;

Transponder supports;



Chain attachment straps;

Tie-in spools

The bundle concept may be applied in riser design to improve thermal insulation and integrity fortransportation of hydrocarbon products at high temperature and high pressure. The bundle riser is tobe designed so that riser, sleeve and carrier pipe are kept apart either by spacers or by connectors atthe end of joints while in the same time considering the flexibility of the system configuration.


C H A P T E R 4 Inspection and Maintenance

CONTENTSSECTION 1 Inspection, Maintenance and Repair ................... 133

1 Inspection ............................................................. 135

3 Maintenance......................................................... 136

5 Pipeline Damages and Repair ............................. 136

7 Pipeline Repair Methods ...................................... 138

SECTION 2 Extension of Use................................................... 139

1 General................................................................. 141

3 Extension of Use .................................................. 141



S E C T I O N 1 Inspection, Maintenance andRepair

CONTENTS1 Inspection ............................................................................ 135

1.1 Inspection and Monitoring Philosophy.................................. 135

1.3 Inspection by Intelligent Pigging........................................... 135

1.5 Monitoring and Control ......................................................... 136

3 Maintenance......................................................................... 136

5 Pipeline Damages and Repair............................................. 136

5.1 Categorization of Damages.................................................. 137

5.3 Damage Assessment ........................................................... 137

7 Pipeline Repair Methods..................................................... 138

7.1 Conventional Repair Methods .............................................. 138

7.3 Maintenance Repair ............................................................. 138



S E C T I O N 1 Inspection, Maintenance andRepair

1 Inspection

1.1 Inspection and Monitoring Philosophy

An inspection and monitoring philosophy is to be established, and this is to form the basis for thedetailed inspection and monitoring program.

Inspection and monitoring are to be carried out to ensure safe and reliable operation of the pipelineand riser system.

1.3 Inspection by Intelligent Pigging

The frequency of intelligent pig inspection is to be determined based on operator’s inspectionphilosophy, and operational risks of the pipe system. The inherent limitations of each inspection toolare to be examined.

1.3.1 Metal Loss Inspection Techniques

Several techniques are applicable, for example:

Magnetic flux leakage;

Ultrasonic;

High frequency eddy current;

Remote field eddy current.

1.3.2 Intelligent Pigs for Purposes Other than Metal Loss Detection

Pipe inspection by intelligent pigging can be categorized into the following five groups ofinspection capability:

Crack detection;

Calipering;

Route surveying;

Free-span detection;

Leak detection.

Chapter 4 Inspection and MaintenanceSection 1 Inspection, Maintenance and Repair 4-1


1.5 Monitoring and Control

Control systems such as these listed below are to be provided to ensure operational safety.

1.5.1 Emergency Shutdown

A means of shutting down the pipe system is to be provided at each of its initial and terminalpoints. The response time of an emergency shut down valve is to be appropriate to the fluid inthe pipe (type and volume) and the operating conditions.

1.5.2 Pressure protection

The pipe system is to be operated in a way that ensures the operating pressure is not exceeded.Primary overpressure protection devices which shut-in the production facilities (wells, pumps,compressors, etc.) are in no case to exceed the maximum allowable operating pressure.Secondary overpressure protection may be set above the maximum allowable operatingpressure, but is not to exceed 90% of System Test Pressure. Such primary and secondaryprotection will protect the pipeline and riser and allow for the orderly shut-in of theproduction facilities in case of an emergency or abnormal operating conditions. In somecases, other overpressure protection device settings, for subsea well pipelines and risers, maybe allowed since the well(s) will be shut-in in case of an emergency at the host facility by theemergency shutdown system.

Instrumentation is to be provided to register the pressure, temperature and rate of flow in thepipeline. Any variation outside the allowable transients is to activate an alarm in the controlcenter.

1.5.3 Pressure, Temperature and Flow Control

To ensure protection of the pipe system against over pressurization and excessively hightemperatures, automatic primary and secondary trips are to be installed. Details includinghigh/low pressure/temperature settings are to be documented in the Operations Manual.

1.5.4 Relief Systems

Relief systems such as relief valves are typically required to ensure that the maximumpressure of the pipe system does not exceed a certain value. Relief valves are to be correctlysized, redundancy provided, and they are to discharge in a manner that will not cause fire,health risk or environmental pollution.

3 MaintenanceThe principle function of maintenance is to ensure that the pipeline and riser continue to fulfill theirintended purpose in a safe and reliable way. Their functions and associated standards of performanceare to be the basis for the maintenance objectives.

Maintenance is to be carried out on all pipeline and riser systems, including associated equipment(e.g. valves, actuators, pig traps, pig signalers and other attachments). Maintenance procedures androutines may be developed accounting for previous equipment history and performance.

5 Pipeline Damages and Repair

In the event of pipe damage threatening the safe continuous transportation of hydrocarbons,inspection, re-assessment, maintenance and repair actions are to be promptly taken as illustratedbelow:

Identify possible cause of damages;



Identify type of encountered damage;

Define pipeline zone criticality and damage categorization;

Identify damage location and assessment techniques;

Outline repair techniques, which may be applied to specific damage scenarios.

5.1 Categorization of Damages

The causes of pipeline damages may be categorized as below:

5.1.1 Internal Damages

Internal corrosion damage occurring as a result of the corrosivity of the transported productand flow conditions in combination with inadequate use of inhibitors. Corrosion damagetends to take place in low points, bends and fittings;

Internal erosion damage occurs through abrasion by the product transported, typically atbends, trees, valves, etc. Erosion may cause deterioration of the inside wall and become aprimary target for corrosion.

5.1.2 External Damages

Dropped objects due to e.g. activities on or surrounding a platform;

Abrasion between cable or chain and the pipe;

In form of a direct hit or dragging due to anchoring;

Damages caused by construction operations, shipping operations, fishing operations.

5.1.3 Environmental Damages

Severe storms and excessive hydrodynamic loads;

Earthquake;

Seabed movement and instability;

Seabed liquefaction;

Icebergs and marine growth.

5.1.4 Types of Pipeline Damages

Damage to pipe wall;

Overstressing or fatigue damages;

Corrosion coating and weight coating damage.

5.3 Damage Assessment

For damaged pipes, ASME B31.4 and B31.8 may be applied to determine whether a damageassessment and repair will be necessary. If a severe damage can not be repaired immediately, strengthassessment of pipes with damages such as dents, corrosion defects and weld cracks may be performedas defined in Appendix 4 of this Guide.



7 Pipeline Repair Methods

7.1 Conventional Repair Methods

Non-critical intervention work such as free-span correction, retrofitting of anode sleds and rockdumping, can usually be considered as planned preventive measures. For the localized repair of non-leaking minor and intermediate pipeline damage, repair clamps may be utilized without the necessityof an emergency shutdown to the pipeline system. For major pipeline damage, resulting in or likely toresult in product leakage, immediate production shutdown and depressurization is invariably required,allowing the damaged pipe section to be and replaced.

7.3 Maintenance Repair

Non-critical repairs that in the short term will not jeopardize the safety of the pipeline, and hence canform part of a planned maintenance program. Examples are:

Corrosion coating repair;

Submerged weight rectification;

Cathodic protection repair;

Span rectification procedures;

Installation of an engineered backfill (rock dumping).



S E C T I O N 2 Extension of Use

CONTENTS1 General................................................................................. 141

3 Extension of Use ................................................................. 141

3.1 Review of Design Documents .............................................. 142

3.3 Inspection ............................................................................. 142

3.5 Strength Analyses ................................................................ 142

3.7 Implementing Repairs/Re-inspection ................................... 142



S E C T I O N 2 Extension of Use

1 GeneralThis Chapter pertains to obtaining and continuance of classification/certification of existing pipelinesbeyond the design life. The classification/certification requires special considerations with respect tothe review, surveys and strength analyses in order to verify the adequacy of the pipeline for itsintended services.

3 Extension of UseTo establish if an existing pipeline is suitable for extended service, the following is to be considered:

Review original design documentation, plans, structural modification records and surveyreports;

Survey pipeline, riser and structures to establish condition;

Review the results of the in-place analysis utilizing results of survey, original plans,specialized geotechnical and oceanographic reports and proposed modifications which affectthe dead, live, environmental and earthquake loads, if applicable, on the pipeline;

Re-survey the pipeline utilizing results from strength analysis. Make any alterations necessaryfor extending the service of the pipeline;

Review a program of continuing surveys to assure the continued adequacy of the pipeline.

The first two items are to assess the pipeline to determine the possibility of continued use. In-placeanalyses may be utilized to identify the areas most critical for inspection at the re-survey.

Fatigue life is sensitive to the waves encountered during the past service and future prediction, andlong-term environmental data is to be properly represented. Should any area be found to be deficient,then these areas require strengthening in order to achieve the required fatigue life. Otherwise,inspection programs are to be developed in order to monitor these areas on a periodical basis.

Fatigue analysis will not be required if the following conditions are satisfied:

The original fatigue analysis indicates that the fatigue lives of all joints are sufficient to coverthe extension of use;

The fatigue environmental data used in the original fatigue analysis remain valid or deemed tobe more conservative;

Cracks are not found during the re-survey or damaged joints and members are being repaired;

Marine growth and corrosion is found to be within the allowable design limits.

Chapter 4 Inspection and MaintenanceSection 2 Extension of Use 4-2


Surveys, as described in Chapter 1, Section 8, are to be undertaken on a periodic basis to ascertain thesatisfactory condition of the pipeline. Additional surveys may be required for pipe systems havingunique features.

3.1 Review of Design Documents

Pipeline design information is to be collected to allow an engineering assessment of a pipeline'soverall structural integrity. It is essential to have the original design reports, documents and as-builtplans and specifications and survey records during fabrication, installation and past service. Theoperator is to ensure that any assumptions made are reasonable and that information gathered is bothaccurate and representative of actual conditions at the time of the assessment. If the information cannot be provided, an assumption of lower design criteria, actual measurements or testing is to becarried out to establish a reasonable and conservative assumption.

3.3 Inspection

Inspection of an existing pipeline, witnessed and monitored by a Bureau Surveyor, is necessary todetermine a base condition upon which justification of continued service can be made. Reports ofprevious inspection and maintenance will be reviewed, an inspection procedure developed, and acomplete underwater inspection required to assure that an accurate assessment of the pipeline'scondition is obtained.

The corrosion protection system is to be re-evaluated to ensure that existing anodes are capable ofserving the extended design life of the pipe system. If found necessary, replacement of the existinganodes or installation of additional new anodes is to be carried out. If the increase in hydrodynamicloads due to the addition of new anodes is significant, this additional load is to be taken into accountin the strength analysis. The condition of protective coatings for risers in the splash zone is to berectified in satisfactory condition.

3.5 Strength Analyses

The strength analyses of an existing pipeline/riser are to incorporate the results of the survey and anystructural modifications and damages. The original fabrication materials and fit-up details are to beestablished such that proper material characteristics are used in the analysis and any stressconcentrations are accounted for. For areas where the design is controlled by earthquake or iceconditions, the analyses for such conditions are also to be carried out. The results of the analyses areconsidered to be an indicator of areas needing inspection. Effects of alterations of structures or seabedto allow continued use are to be evaluated by analysis. Free spans where strength criteria are violatedmay be improved by seabed intervention. The results of these load reductions on the structure are tobe evaluated to determine whether the repairs/alterations is needed.

3.7 Implementing Repairs/Re-inspection

The initial condition survey in conjunction with structural analysis will form the basis for determiningthe extent of repairs/alterations, which will be necessary to class the pipeline for continued operation.

A second survey may be necessary to inspect areas, which the analysis results indicate as being themore highly stressed regions of the structure. Areas found overstressed are to be strengthened. Weldswith low fatigue lives may be improved either by strengthening or grinding. If grinding is used, thedetails of the grinding are to be submitted to the Bureau for review and approval. Intervals of futureperiodic surveys are to be determined based on the remaining fatigue lives of these welds.


A P P E N D I X 1 Limit State Design Criteria

CONTENTSSECTION 1 Limit State Design Principles............................... 145

1 Limit State Design ................................................ 145

SECTION 2 Classes for Containment, Location, MaterialQuality and Safety................................................. 147

1 Classification of Containment............................... 149

3 Classification of Location ..................................... 149

5 Classification of Material Quality .......................... 150

7 Classification of Safety......................................... 151

SECTION 3 Limit State for Bursting ........................................ 153

1 Hoop Stress Criteria ............................................. 153

3 System Pressure Test.......................................... 153

SECTION 4 Limit State for Local Buckling.............................. 155

1 Maximum Allowable Moment ............................... 157

3 Effects of Manufacturing Process ........................ 159

5 Usage Factors ...................................................... 159

7 Condition Load Factors ........................................ 159

SECTION 5 Limit State for Fracture of Girth Weld Crack-likeDefects................................................................... 161

1 Possible Cracks in Girth Weld.............................. 163

3 Fracture of Cracked Girth Welds ......................... 164

5 Fatigue Crack Propagation .................................. 165

SECTION 6 Limit State for Fatigue .......................................... 167

1 Fatigue Assessment Based on S-N Curves......... 169

3 Fatigue Assessment Based on ∆ε-N Curves ....... 170

5 Fatigue Assessment Based on FractureMechanics ............................................................ 170

SECTION 7 Limit State for Ratcheting/Out-of-roundness...... 171

SECTION 8 Finite Element Analysis of Local Strength.......... 173

1 Modeling of Geometry and BoundaryConditions ............................................................ 175

3 Mesh Density........................................................ 175

5 Material................................................................. 176

7 Loads and Load Sequence .................................. 176

9 Validation.............................................................. 176



S E C T I O N 1 Limit State Design Principles

1 Limit State Design

1.1 Strength Requirements

The strength requirements for pipeline and riser design will normally be satisfied if the followingLimit States are fulfilled:

Bursting;

Local buckling and collapse;

Fracture;

Fatigue;

Ratcheting/Out-of-roundness.

1.3 Limit States

The Limit States, given in form of maximum allowable limits such as strain, stress and bendingmoments and are to be checked for the following design scenarios:

Installation;

Empty condition;

Water filled condition;

Pressure test condition;

Operational conditions.

1.5 Maximum Allowable Limits

The maximum allowable limits are based on equations predicting the ultimate strength, to whichreduction factors are applied to address uncertainties in strength estimation and consequences relatedto failure:

Statistical values for design equations;

Statistical values for material properties;

Complexity of conditions to be modeled;

Location zone.



S E C T I O N 2 Classification of Containment,Location, Material Quality andSafety

CONTENTS1 Classification of Containment ............................................ 149

3 Classification of Location ................................................... 149

5 Classification of Material Quality........................................ 150

7 Classification of Safety ....................................................... 151

TABLE 1 Classification of Containment ................................ 149

TABLE 2 Classification of Location ....................................... 150

TABLE 3 Classification of Material Quality............................ 150

TABLE 4 Definition of Safety Classes.................................... 151

TABLE 5 Classification of Safety Classes Pipelines andRisers Attached to Fixed Platforms........................ 151

TABLE 6 Classification of Riser Safety Classes (RisersConnected to Floating Installations) ...................... 151

TABLE 7 Classification of Safety Classes for Bundles......... 151



S E C T I O N 2 Classification of Containment,Location, Material Quality andSafety

This Appendix recommends Limit State design factors reflecting appropriate safety levels,containment hazard levels, consequences of failure related to life, environment and business togetherwith uncertainties related to material resistance and loads acting on the pipe. The recommendedfactors will be applicable for most pipeline and riser designs, but where this Appendix is deemedinadequate, the establishment of alternative safety factors is to be verified by the Bureau.

1 Classification of Containment

The containment being transported is to be identified and categorized according to A1-2/Table 1.

TABLE 1Classification of Containment

Category Description

A Contents in form of gases and/or liquids that at ambient temperature and atmospheric pressureare non-flammable and non-toxic. Examples: water, water-based fluids, nitrogen, carbondioxide, argon and air.

B Contents in form of gases and/or liquids that at ambient temperature and atmospheric pressureare flammable, toxic and/or could lead to environmental pollution if released. Examples: oil,petroleum products, toxic liquids, hydrogen, natural gas, ethane, ethylene, ammonia, chlorine,liquefied petroleum gas (such as propane and butane), natural gas liquids etc.

If the containment being carried is not among the gases or liquids mentioned in A1-2/Table 1, it is tobe classified in the category containing substances most similar in hazard potential to those quoted. Ifany doubt arises as to the contents being transported, hazardous classification B is to be assumed.

3 Classification of Location

The pipeline system is to be classified into location classes as defined in A1-2/Table 2.

Appendix 1 Limit State Design CriteriaSection 2 Classification of Containment, Location, Material Quality and Safety A1-2


TABLE 2Classification of Location

Zone Description

1 Areas where infrequent human activity is anticipated (to be documented).

2 Areas adjacent to manned platforms and areas where frequent human activity is anticipated.

5 Classification of Material QualityThe material quality used for linepipes designed based on the format given in this Appendix are tomeet the requirements of chemical composition and mechanical properties as defined by ISO31831~3. The material quality is to be classified as A, B or C, as given by A1-2/Table 3.

TABLE 3Classification of Material Quality

Material Quality Description

Class A A basic quality level corresponding to that specified in the main part of API SPEC 5L, orISO 3183-1.

Class B For transmission pipelines and risers, overall enhanced requirements (e.g. concerningtoughness and non-destructive testing) are addressed, as specified by ISO 3183-2

Class C For particularly demanding applications where very stringent requirements (e.g. concerningsour service, fracture arrest properties, plastic deformation) on quality and testing are imposed,ISO 3183-3.

The tensile and Charpy V-notch impact properties are to be in accordance with relevant specifications,such as API SPEC 5L or ISO3183 1~3. Tensile properties of the linepipe are to be tested in bothtransverse and longitudinal directions, while Charpy V-notch samples are to be tested only in thetransverse direction.

Materials are to exhibit fracture toughness that is satisfactory for the intended application, assupported by previous satisfactory service experience or appropriate toughness tests. Where thepresence of ice is judged as a significant environmental factor, material selection may require specialconsideration.

The following requirements with respect to the definition of Specified Minimum Yield Strength andSpecified Minimum Tensile Strength in the circumferential direction are to be fulfilled:

SMYS < (mean – 2*Standard Deviations) of yield stress;

SMTS < (mean – 3*Standard Deviations) of tensile stress.

The material yield stress and tensile stress are to be obtained through testing at relevant temperaturesand test results submitted to the Bureau.

Material anisotropy is defined by the ratio between material properties in the transverse direction andthose in the longitudinal direction, and are, where appropriate, to be accounted for in the strengthcalculations.

For pipelines and risers or sections of these to be operated at temperatures above 50°C (120°F),appropriate material resistance de-rating factors are to be established and applied to the specifiedminimum yield and tensile strength.

For linepipes manufactured by the UO or UOE method, the influence of the manufacturing process onthe yield stress is to be accounted for in the design. If the material’s specified minimum yield stress isless than 70 ksi, the values given in 3-4/7 may be used, otherwise the influence of the manufacturingprocess is to be based on testing.

Appendix 1 Limit State Design CriteriaSection 2 Classification of Containment, Location, Material Quality and Safety A1-2


7 Classification of SafetyThe definition of safety classes used in this Appendix is in accordance with A1-2/Table 4.

TABLE 4Definition of Safety Classes

Safety Class Description

Low Failure implies no risk to human safety and only limited environmental damage and economiclosses.

Normal Failure implies negligible risk to human safety and only minor damage to the environment, butmay imply certain economic losses.

High Failure implies risk to the total safety of the system so as to human safety and environmentalpollution. High economic losses may apply.

For normal use, the safety classes in A1-2/Table 5 to A1-2/Table 7 apply. Other safety classificationmay be justified based on the design target reliability level of the pipeline, but are in such cases to besubmitted for approval by the Bureau.

TABLE 5Classification of Safety Classes

Pipelines and Risers Attached to Fixed Platforms

Content Category A Content Category BLoad Condition

Location Zone 1 Location Zone 2 Location Zone 1 Location Zone 2

Temporary Low Low Low Low

Operational Low Normal Normal High

Abnormal Low Normal Low Normal

TABLE 6Classification of Riser Safety Classes

(Risers Connected to Floating Installations)

Content Category A Content Category BLoad Condition

Location Zone 1 Location Zone 2 Location Zone 1 Location Zone 2

Temporary N/A Low N/A Normal

Operational N/A Normal N/A High

Abnormal N/A Normal N/A Normal

TABLE 7Classification of Safety Classes for Bundles

Pipes Launch & Installation Operation

Flowlines Low Normal

Heat-Up Lines Low Low

Carrier pipe and Sleeve Normal Low



S E C T I O N 3 Limit State for Bursting

1 Hoop Stress CriteriaThe hoop stress is not to exceed the following:

]87.0,00.1min[2

)( SMTSSMYSt

tDpp sei ⋅⋅⋅≤

⋅−− η

where

pi = internal pressure

pe = external pressure

D = nominal outside steel diameter of pipe

t = minimum wall thickness

SMYS = Specified Minimum Yield Strength at design temperature

SMTS = Specified Minimum Tensile Strength at design temperature

De-rating of material resistance is, where applicable, to be accounted for in the definition of SpecifiedMinimum Yield Strength and Specified Minimum Tensile Strength at elevated design temperatures.

For thick walled pipes with a D/t < 20 the above hoop stress criteria may be adjusted based on e.g.BS 8010-3.

The usage factors for hoop stress criteria are given in A1-3/Table 1.

TABLE 1Usage Factors for Hoop Stress Criteria

Safety ClassMaterial Quality Usage Factor

Low Normal High

Class B, C ηs 0.85 0.80 0.70

Class A ηs 0.83 0.77 0.67

3 System Pressure TestThe pipeline and riser system is to be subjected to a system pressure test after installation inaccordance with Chapter 3, Section 4.



S E C T I O N 4 Limit State for Local Buckling

CONTENTS1 Maximum Allowable Moment.............................................. 157

3 Effects of Manufacturing Process...................................... 159

5 Usage Factors...................................................................... 159

7 Condition Load Factors ...................................................... 159

TABLE 1 Usage Factors .......................................................... 159

TABLE 2 Condition Load Factors for Limit State Design ..... 159



S E C T I O N 4 Limit State for Local Buckling

Local buckling may occur due to excessive bending combined pressure and longitudinal force. Thefailure mode will be a combination of local yielding and flattening/local buckling and mainly dependson the diameter to wall thickness ratio, load condition, and local imperfections in material andgeometry. Initial out-of-roundness is the only local imperfection accounted for in the equationspresented in this Appendix. The formulas in this section are applicable to diameter to thickness ratiosbetween 10 and 60. For pipes of larger D/t ratio, the use of the moment criterion is subject to theapproval of the Bureau. The criteria will be applicable to steel pipes, but may be applied to titaniumpipes provided an equivalent SMYS is defined as the minimum of SMYS and SMTS/1.3.

1 Maximum Allowable Moment

The maximum allowable bending moment MAll ensuring structural strength against local bucklingmay be found by:

⋅−−

⋅−⋅⋅

⋅−−⋅=

22

22

)1(12

cos)1(1

p

p

p

p

F

F

p

pMM

RP

RPRF

c

RPc

RMAll

ηα

µα

ηγ

πη

αγ

η

where

p = pressure acting on the pipe (pi − pe)

F = true longitudinal force acting on the pipe

γC = condition load factor

ηR = strength usage factors

The moment M , which is the moment capacity in pure bending, may be calculated as:

tDSMYSt

DM ⋅⋅⋅

⋅−= 20015.005.1

where

SMYS = Specified Minimum Yield Strength in longitudinal direction at designtemperature

D = average diameter

t = wall thickness

Appendix 1 Limit State Design CriteriaSection 4 Limit State for Local Buckling A1-4


The longitudinal force F may be estimated as:

F = 0.5∙(SMYS + SMTS)∙A

where

A = cross sectional area, which may be calculated as π × D × t.

SMYS = Specified Minimum Yield Strength in longitudinal direction at designtemperature

SMTS = Specified Minimum Tensile Strength in longitudinal direction at designtemperature

The pressure p is for external overpressure conditions equal to the pipe collapse pressure and may becalculated based on:

020

223 =⋅+⋅

⋅⋅⋅+−⋅− pepepe ppp

t

Dfpppppp

where

pe = 3

2 )1(

2

⋅

−⋅

D

tE

ν

pp = D

tSMYSk fab

⋅⋅⋅ 2


t = wall thickness

f0 = initial out-of-roundness (1), (Dmax – Dmin)/D, not to be taken less than 0.5%

SMYS = Specified Minimum Yield Strength in hoop direction at design temperature

E = Young’s Modulus at design temperature


kfab = Material resistance de-rating factor due to fabrication

Notes:1 Out-of-roundness caused during the construction phase is to be included, but not flattening due to

external water pressure or bending in as-laid position. Increased out-of-roundness due to installation andcyclic operating loads may aggravate local buckling and is to be considered. It is recommended that out-of-roundness due to through-life cyclic loads be simulated, if applicable.

For internal overpressure conditions, the pressure p is equal to the burst pressure, which may befound as:

( )tD

tSMYSSMTSp

−⋅⋅+⋅= 2

5.0

where

SMYS = Specified Minimum Yield Strength in hoop direction at design temperature

SMYS = Specified Minimum Tensile Strength in hoop direction at design temperature


t = wall thickness

Appendix 1 Limit State Design CriteriaSection 4 Limit State for Local Buckling A1-4


The strength anisotropy factor α may be calculated as:

F

pD c⋅⋅=4

2πα , for external overpressure;

F

pD b⋅⋅=4

2πα , for internal overpressure.

3 Effects of Manufacturing ProcessThe material strength in the hoop direction will be influenced by the manufacturing process and if notest data are available for the hoop strength, the reduction factor kfab given in 3-4/7 is to be used.

5 Usage Factors

Usage factors ηR are listed in A1-4/Table 1

TABLE 1Usage Factors

Usage Factors ηRP ηRF ηRM

Low 0.95 0.90 0.80

Normal 0.93 0.85 0.73

High 0.90 0.80 0.65

7 Condition Load FactorsTo account for uncertainties related to the modeling of certain load conditions, condition load factorsare introduced in accordance with A1-4/Table 2.

TABLE 2Condition Load Factors for Limit State Design

Load condition Condition load factor, γC

Uneven seabed 1.06

Continuously stiff supported 0.85

System pressure test 0.94

Otherwise 1.0



S E C T I O N 5 Limit State for Fracture of GirthWeld Crack-like Defects

CONTENTS1 Possible Cracks in Girth Weld............................................ 163

3 Fracture of Cracked Girth Welds........................................ 164

3.1 Level 1 Assessment – Workmanship Standards.................. 164

3.3 Level 2 Assessment – Alternative AcceptanceStandards ............................................................................. 164

3.5 Level 3 Assessment – Detailed Analysis ............................. 164

5 Fatigue Crack Propagation ................................................. 165



S E C T I O N 5 Limit State for Fracture of GirthWeld Crack-like Defects

Fracture in welds due to tensile strain is normally evaluated in accordance with a recognizedassessment method based on the failure assessment diagram, which combines the two potential failuremodes: brittle fracture and plastic collapse. This Section may be applied to define acceptance criteriafor inspection of girth welds.

1 Possible Cracks in Girth Weld

Various types of imperfections are known to occur in girth welds. The most damaging types arecracks, inadequate penetration of the root bead and lack of fusion. The imperfections are particularlydamaging if they occur in a weld that significantly under-matches the yield strength of the basematerial.

When evaluating the risk of fracture failure for girth welds, assumptions are to be made regardingtypes, dimensions and locations of weld defects. The most frequently seen type of planar/crack-likedefect in one-sided Shielded Metal Arc Welding is lack-of-fusion defects. Such defects can be locatednear the surface, at the root of the weld toe or be surface breaking and may have gone undetectedwhen following non-destructive testing procedures according to API STD 1104.

Maximum weld flaws are to be used as the basic input for the assessment. The flaw may be assumedas maximum allowable defect due to lack of fusion between passes. Surface flaw is chosen as theworst case scenario from acceptable flaws specified in the welding procedure specifications. Thedefect sizes to be used in the fracture assessment are to be based on the welding methods used and theaccuracy of the non-destructive testing during construction. If no detailed information is available, thedefects and material may be taken as below:

Type: Surface flaw due to lack of fusion

Depth (a): Minimum of 0.118 inch (3 mm) and nominal wall-thickness divided bynumber of welding passes

Length (2c): 2c < min [2t, 2 1.97 inch (50 mm)]

CTOD: 0.003 inch (0.075 mm) or as given by welding specifications

Material: As for parent material

The fracture failure of welds is highly dependent on the weld matching and on the ratio of yield totensile strength. An adequate strain concentration factor is to be established accounting for thestiffness of coatings and buckle arrestors.

Appendix 1 Limit State Design CriteriaSection 5 Limit State for Fracture of Girth Weld Crack-like Defects A1-5


3 Fracture of Cracked Girth Welds

Defects in girth welds can be assessed on one of three levels, depending upon the quality of theaffected welds, the availability of relevant material data and difficulties related to repairs. Level 1 is tobe mandatory where acceptance levels are graded according to criticality of application. Level 2 is tobe a conservative initial assessment. Level 3 is to be applied to details that fail in Level 2.

3.1 Level 1 Assessment – Workmanship Standards

Pipeline welding codes establish minimum weld quality standards based on inspection of welder'sworkmanship, and the flaw acceptance criteria are evolved through industry experience. Hence, mostworkmanship standards are similar, though not identical, in terms of allowable imperfection types andsizes.

The workmanship standards may be based on API STD 1104 or standards such as ASME Boiler andPressure Vessel Code, CSA Z662 and BS 4515.

3.3 Level 2 Assessment – Alternative Acceptance Standards

Alternative acceptance standards have been developed to facilitate acceptance of flaws that do notmeet workmanship standards. Incentives for alternative standards are usually economic, arising due tothe inaccessibility or quantity of welds that would otherwise be repaired. Alternative standardsrecognize that the true severity of a flaw is dependent on material toughness and applied stress levels,and can only be determined using fracture mechanics principles.

CTOD is established from destructive tests performed on weldments. If the pipeline is yet to beconstructed, CTOD tests can be performed as part of the weld procedure qualification. If the pipelineis already in service and CTOD data are not available, the welding procedures, consumable, and basematerials used in construction may be used to duplicate welds for the purpose of conducting CTODtests. If any of these elements is no longer available, it will be necessary to obtain a representativeweld for testing. Alternatively, a lower-bound CTOD of 0.003 inch (0.075 mm) may be assumed inlieu of tests.

Alternative criteria are given in codes and standards, such as in Appendix to API STD 1104,Appendix K to CSA Z662, BSI 7910, and the EPRG Guidelines on assessment of defects intransmission pipeline girth welds.

3.5 Level 3 Assessment – Detailed Analysis

A more detailed analysis is to use FAD’s and tearing stability analysis from BS 7910, API RP 579 orequivalent.

BS 7910 Level 2 provides three possible FAD’s:

Generalized curve for low work hardening materials;

Generalized curve for low and high work hardening materials;

Material specific curve.

Level 3 in BS 7910 covers tearing instability analysis.

In the assessment of the fracture failure capacity of the weld due to longitudinal strain of the pipe,surface breaking flaws may be idealized as semi-elliptical surface weld defects of depth, a, and totallength, 2c. a and c are to be based on non-destructive test measurements with a minimum not less thanthe minimum detectable crack size by the applied non-destructive test method. Parametric solutionsfor K are available in codes such as API RP 579 and BS 7910.

Appendix 1 Limit State Design CriteriaSection 5 Limit State for Fracture of Girth Weld Crack-like Defects A1-5


The critical stress levels with respect to failure (e.g. fracture, plastic collapse of remaining ligament)can be obtained from Failure Assessment Diagram analysis, for the different pipelines as a function ofthe degree of corrosion wall-thickness reduction. The corresponding critical strain level is estimatedusing the Ramberg-Osgood curve for the stress-strain relationship.

5 Fatigue Crack PropagationThe fatigue crack propagation rate may be obtained following the procedure described in A1-6/5 orrefer to basic fracture mechanics methodology as per BS 7910, API RP 579 or equivalent.

Use actual da/dN versus ∆K and ∆K data wherever possible. Fit Paris’ equation over entire range ofdata or fit alternative crack growth law (e.g. Forman equation, see API RP 579 for others).Alternatively, fit Paris’ equation in piece-wise linear manner. The latter may be the most effective forcrack growth in seawater with/without cathodic protection. In the absence of specific da/dN data, useupper bound relationships in BS 7910, API RP 579 or equivalent.

Fatigue life versus crack depth may be predicted by integrating ∆a/∆N versus ∆K relationship usingweight average ∆K or cycle-by-cycle approach if interaction effects are negligible.



S E C T I O N 6 Limit State for Fatigue

CONTENTS1 Fatigue Assessment Based on S-N Curves....................... 169

3 Fatigue Assessment Based on ∆∆∆∆εεεε-N Curves ..................... 170

5 Fatigue Assessment Based on Fracture Mechanics......... 170



S E C T I O N 6 Limit State for Fatigue

Risers, unsupported pipeline spans, welds, J-lay collars, buckle arrestors, riser touchdown points andflex-joints, are to be assessed for fatigue. Potential cyclic loading that can cause fatigue damageincludes vortex-induced-vibrations, wave-induced hydrodynamic loads, floating installationmovements and cyclic pressure and thermal expansion loads. The fatigue life is defined as the time ittakes to develop a through-wall-thickness crack.

Fatigue analysis and design can be conducted using:

S-N approach for high cycle fatigue (and low cycle fatigue of girth welds may be checkedbased on ∆ε-N curves.);

Fracture mechanics approach;

Hybrid approach (Combination of S-N and fracture mechanics approaches).

It is recommended that S-N approach be prioritized for design purpose. The fracture mechanicsapproach is recommended for assessments or reassessments and establishment of inspection criteria. Itshould be noted that the S-N approach and fracture mechanics approach should produce very similarresults. Different acceptance criteria could be applied for different approach. In general, design lifecriteria should be adopted when using the S-N approach, while through-thickness crack criteria are tobe applied for the fracture mechanics approach. In order to achieve a consistent safety level, it mightbe necessary to calibrate the initial crack size in the fracture mechanics approach against the S-Napproach.

1 Fatigue Assessment Based on S-N Curves

For assessment of high cycle fatigue, fatigue strength is to be calculated based on laboratory tests(S-N curves) or fracture mechanics. In the limit state based fatigue analysis, appropriate partial safetyfactors are to be defined and applied to loads and material strength prior to the estimation of theaccumulated fatigue damage.

Typical steps required for fatigue analysis using the S-N approach are outlined below.

Estimate long-term stress range distribution;

Select appropriate S-N curve;

Determine stress concentration factor;

Estimate accumulated fatigue damage using Palmgren-Miner’s rule.

Appendix 1 Limit State Design CriteriaSection 6 Limit State for Fatigue A1-6


The S-N curves to be used for fatigue life calculation may be defined by the following formula:

log N – log a – m⋅log∆σ

where N is the allowable stress cycle numbers; a and m are parameters defining the curves, which aredependant on the material and structural detail. ∆σ is the stress range including the effect of stressconcentration.

Multiple linear S-N curves in logarithmic scale may be applicable. Each linear curve may then beexpressed as the above equation.

The fatigue damage may be based on the accumulation law by Palmgren-Miner:

η≤= ∑=

cM

i i

ifat N

nD

1

where

Dfat = accumulated fatigue damage

η = allowable damage ratio, to be taken in accordance to 3-4/11

Ni = number of cycles to failure at the ith stress range defined by the S-N curve

ni = number of stress cycles with stress range in block i

3 Fatigue Assessment Based on ∆ε-N CurvesThe number of strain cycles to failure may be assessed according to the American Welding Society(AWS) Standards ∆ε-N curves, where N is a function of the range of cyclic bending strains ∆ε. The∆ε-N curves are expressed as below:

∆ε = 0.055N-0.4 for ∆ε ≥ 0.002 and

∆ε = 0.016N-0.25 for ∆ε ≥ 0.002

The strain range ∆ε is the total amplitude of strain variations; i.e. the maximum less the minimumstrains occurring in the pipe body near the weld during steady cyclic bending loads.

5 Fatigue Assessment Based on Fracture MechanicsIn the fracture mechanics approach, the crack growth is calculated using Paris’ equation and the finalfracture found in accordance with recognized failure assessment diagrams. It may be applied todevelop cracked S-N curves for pipes containing initial defects. If a crack growth analysis isperformed by the fracture mechanics method, the design criterion for fatigue life is to be at least 10times the service life for all components. The initial flaw size is to be the maximum acceptable flawspecified for the non-destructive testing during manufacture of the component in question.

Typical steps required for fatigue analysis using the fracture mechanics approach are outlined below:

Estimate long-term stress range distribution;

Determine stress concentration factor;

Select appropriate material parameter to be used in Paris’ equation;

Determine initial crack size and crack initiation time;

Determine the critical crack size;

Determine geometry function for stress intensity factor;

Integrate Paris’ equation to estimate fatigue life.



S E C T I O N 7 Limit State for Ratcheting/Out-of-roundness

The pipeline out-of-roundness is related to the maximum and minimum pipe diameters (Dmax andDmin) measured from different positions around the sectional circumference according to:

D

DDf minmax −=0

Out-of-roundness introduced during manufacturing, storage and transportation is generally not toexceed 0.75%. For design the initial out-of-roundness is not to be assumed less than 0.50%.

The out-of-roundness of the pipe may increase where the pipe is subject to reverse bending and theeffect of this on subsequent straining is to be considered. For a typical pipeline the followingscenarios will influence the out-of-roundness:

Reverse inelastic bending during installation;

Cyclic bending due to shutdowns in operation if global buckling is allowed to relievetemperature and pressure induced compressive forces.

Critical point loads may arise at free-span shoulders, artificial supports and support settlement.

Out-of-roundness accumulative through the life cycle is, if applicable, to be found from ratchetinganalysis. Out-of-roundness is not to exceed 2% unless:

Effect of out-of-roundness on moment capacity and strain criteria is included;

Requirements for pigging and other pipe run tools are met.

Ratcheting is described in general terms as signifying incremental plastic deformation under cyclicloads in pipelines subject to high pressure and high temperatures. The effect of ratcheting on out-of-roundness and local buckling is to be considered.

A simplified code check of ratcheting is that the equivalent plastic strain is not to exceed 0.1%, asdefined based on elastic-perfectly-plastic material and assuming that the reference state for zero strainis the as-built state after mill pressure testing.

The finite element method may be applied to quantify the amount of deformation induced byratcheting during the life cycle of a pipeline or riser.



S E C T I O N 8 Finite Element Analysis of LocalStrength

CONTENTS1 Modeling of Geometry and Boundary Conditions............. 175

3 Mesh Density ....................................................................... 175

5 Material................................................................................. 176

7 Loads and Load Sequence ................................................. 176

9 Validation ............................................................................. 176



S E C T I O N 8 Finite Element Analysis of LocalStrength

If adequate documentation is presented, alternative methods for estimating the strength capacity ofpipes subjected to combined loads may be accepted for installation and seabed intervention design.An important tool is the finite element method, which allows the designer to model the geometry,material properties and imperfections such as out-of-roundness, field joints, attachments and corrosiondefects and thereafter estimate the maximum strength for a given load scenario. Another importantissue is the effect of cyclic loads. Cyclic loads may aggravate/increase imperfections and fatiguedamage, which may end up reducing the design life.

1 Modeling of Geometry and Boundary ConditionsWhen applicable, the size of a finite element model may be reduced by introducing symmetryboundary conditions. For this approach to be valid, material, geometry and loads are to besymmetrically distributed around the same symmetry line. This approach may reduce finite elementmodels to one half or less of the pipe section.

It is important that the modeled pipe section includes all features and attachments relevant for thestress distribution in the pipe and that the model is sufficiently long to catch relevant failure modes.

Imperfections such as out-of-roundness, weld defects/misalignment and corrosion defects may reducethe strength of the pipe considerably, and the largest realistic imperfections are to be included in themodel. Imperfections that might be insignificant for some load conditions will be catastrophic forothers. An example is out-of-roundness, which has negligible influence on the burst strength, while itmight reduce the collapse strength due to considerable external overpressure. If differentimperfections are combined, their mutual orientation might influence the pipe strength. An example iscombined out-of-roundness and corrosion defects. Here, the worst orientation of the out-of-roundnesswith regard to pipe strength might change with increasing size of a corrosion defect.

3 Mesh Density

The mesh density generally depends on the selected element definition and detail level of the analysis.Selection of element definition and mesh density/distribution is generally to be based on engineeringexperience, but it is recommended that sensitivity studies be performed to demonstrate the adequacyof the chosen mesh. This exercise will normally be a part of the verification procedure for the model.

Appendix 1 Limit State Design CriteriaSection 8 Finite Element Analysis of Local Strength A1-8


5 Material

The material input to Finite Element Software is to be based on the software used and the problem tobe solved. For pure elastic analysis it will normally be enough to describe the material characteristicin the form of the modulus of elasticity and Poisson’s ratio, while for analysis including material non-linearity it will be necessary to include a description of the material’s plastic behavior. It is hereimportant to notice that finite element programs might use either a true stress-strain or engineeringstress-strain relationship.

It is important to consider if residual stresses in the material are to be included in the model. Forpipelines, residual stresses in both longitudinal and hoop directions might be introduced through theforming process or by seam welding. Effects of these residual stresses are in general considerednegligible for pipeline analysis, but practice has demonstrated that this is not always the case.

When cyclic inelastic loading is to be modeled, a nonlinear combined isotropic and kinematic materialmodel may be applied. This material model will also be applicable for low cycle fatigue studies.

7 Loads and Load Sequence

The sequence of applied loads may influence the result, and if the sequence is not known, several testsare to be performed to make sure that the results represent the worst case. As an example, a pipesubjected first to axial tension and then pressure, might burst at a higher pressure than for the purepressure condition, and visa versa.

9 Validation

Finite element models and other analysis models in general, are to be validated against appropriatemechanical tests and the validation approved by the Bureau before they are used in design.


A P P E N D I X 2 Structural Reliability Analysis

CONTENTS1 Structural Reliability............................................................ 179

3 Reliability-Based Design..................................................... 179

5 Limit State Function ............................................................ 180

7 Calculation of Failure Probability....................................... 180

7.1 Analytical Approach.............................................................. 180

7.3 Simulation Methods.............................................................. 180

9 Uncertainty Measures ......................................................... 180

9.1 Classification of Uncertainties .............................................. 180

9.3 Selection of Distribution Functions....................................... 181

9.5 Determination of Statistical Values ...................................... 181

11 Calibration of Safety Factors .............................................. 181

11.1 Target Reliability Levels ....................................................... 181

13 Reliability-based Inspection Planning ............................... 182

13.1 Inspection Planning for Corrosion Defects........................... 182


A P P E N D I X 2 Structural Reliability Analysis

This Appendix presents guidelines on reliability-based limit-state design, which are to be used indesign and re-qualification of pipelines. The methodology for reliability analysis, uncertaintymeasures, target reliability levels, calibration of safety factors, inspection and updating aresummarized.

1 Structural Reliability

As an alternative to the Working Stress Design format specified and used in this Guide, a recognizedstructural reliability-based design method may be applied provided that:

Approach is demonstrated to provide adequate safety for familiar cases;

Suitably competent and qualified engineers perform the structural reliability analysis andextension into new areas of application is supported by technical verification.

Structural reliability methods consider limit-state functions in conjunction with available informationof the involved variables and their associated uncertainties. The reliability, as assessed by reliabilitymethods, is not an objective physical property of the pipeline in the given operational andenvironmental conditions, but rather a nominal measure of the reliability and analysis procedureapplied.

A structural reliability analysis is only one part of a total safety concept, as gross errors are notincluded.

Target reliabilities are to be met in reliability-based design to ensure that a required safety level isachieved.

3 Reliability-Based Design

In principle, reliability-based design of offshore pipelines involves the following aspects:

Identification of failure modes for specified design scenarios;

Definition of design formats and Limit State Functions;

Uncertainty measurements of all random variables used in Limit State Functions;

Calculation of failure probability;

Determination of target reliability levels;

Calibration of safety factors for design;

Evaluation of design results.

Appendix 2 Structural Reliability Analysis A2


5 Limit State Function

A limit state function is defined for a failure mode in accordance with the chosen failure criterion andmay contain both random variables and deterministic variables. As a simple example, the limit statefunction g(z) can be expressed as:

g(z) = R(z) – S(z)

where z denotes the vector of basic variables. R and S are resistance and load effect, respectively.

7 Calculation of Failure Probability

Failure occurs when g(z) ≤ 0. For a given Limit State Function g(z), the probability of failure isdefined as:

Pf(t) = p[g(z) ≤ 0]

The results can also be expressed in terms of a reliability index β and the failure probability that arerelated by:

β(t) = −Φ-1[Pf(t)] = Φ-1[Pf(t)]

where Φ(...) symbolizes the standard normal distribution function.

In general, the failure probability can be calculated by using either an analytical approach or asimulation method.

7.1 Analytical Approach

Analytical methods generally use First- and Second-Order Reliability Methods (FORM and SORM)and do usually not require large computing costs. However, analytical methods require an explicitform of limit state functions.

7.3 Simulation Methods

Simulation methods such as the Monte Carlo technique are an alternative or complementary tool forthe calculation of failure probability. The advantage of this technique is that the methods are verysimple and give solutions that converge towards exact results when a sufficient number of simulationsare performed. The disadvantage of the simulation methods is that their computing efficiency is low.

9 Uncertainty MeasuresFailure probability is evaluated based on uncertainties of the random variables used in Limit StateFunctions. Uncertainty measures are a critical and fundamental step in structural reliability analysis.The major steps involved in the uncertainty evaluation includes the following:

Classification of uncertainties;

Selection of distribution functions;

Determination of statistical values used to define the random variables.

9.1 Classification of Uncertainties

Uncertainty of a random variable can be measured using a probability distribution function andstatistical values. The major uncertainties include the following:



9.1.1 Physical Uncertainty

Physical uncertainties are due to the random nature of the actual variability of physicalquantities, such as pipe geometry (wall thickness), etc.

9.1.2 Statistical Uncertainty

Statistical uncertainties result from incomplete information of variables and will generally bea function of the used distribution function, the applied estimation technique, the value of thedistribution parameters and amount of underlying data. Statistical uncertainty may furtheroccur due to negligence of systematic variations of the observed variables. This uncertaintycan be reduced by additional information of the variable in terms of its statistical significance.

9.1.3 Model Uncertainty

Model uncertainty is related to the physical model representing load and resistance quantitiesand may be expressed in term of a stochastic factor defined as the ratio of the true quantity tothe quantity described by the analytical model. It results in the difference between actual andpredicted results.

9.3 Selection of Distribution Functions

Usually, the determination of the distribution function is strongly influenced by the physical nature ofthe random variables. Also, its determination may be related to a well-known description andstochastic experiment. Experience from similar problems is also very useful. If several distributionsare available, it is necessary to identify them by plotting of data on probability paper, by comparisonsof moments, statistical tests, etc. Normal or lognormal distributions are normally applied when nodetailed information is available. For instance, resistance variables are usually modeled by normaldistribution, and lognormal distribution is used for load variables. The Poisson distribution may beused to describe the occurrence frequency of damages, such as initial cracks. Exponential distributionis used to model the capacity of detecting a certain defect.

9.5 Determination of Statistical Values

Random variables are to be described in terms of statistical values, such as the mean value and theCoefficient of Variation. These statistical values are normally to be obtained from recognized datasources. Regression analysis may be applied based on methods of moment, least square fit methods,maximum likelihood estimation technique, etc.

11 Calibration of Safety Factors

One of the important applications of structural reliability methods is to calibrate safety factors indesign format in order to achieve a consistent safety level. The safety factors are determined so thatthe calibrated failure probability for various conditions is as close to the target reliability level aspossible.

11.1 Target Reliability Levels

When conducting structural reliability analysis, target reliability levels in a given reference timeperiod and a reference length of pipeline are to be selected. The selection is based on consequence offailure, location, contents, relevant rules, access for inspection and repair, etc. The target reliabilitylevels are to be met in design to ensure that certain safety levels are maintained.

As far as possible, target reliability levels are to be calibrated against identical or similar pipelinedesigns that are known to have adequate safety. If this is not feasible, the target safety level is to bebased on the failure type and safety class.



Target reliability levels may be specified by the Operator guided by authority requirements, designphilosophy and risk attitude.

13 Reliability-based Inspection Planning

Generally, in-service inspections for pipelines and risers are to be in accordance with Section 4/2.1 orother relevant codes. Structural reliability methodology can be applied to optimize in-serviceinspection planning.

To cover the most frequent damages to pipelines and risers, two kinds of inspection are considered:

Inspection of corrosion defects;

Inspection of fatigue cracks for risers, e.g. near the splash zone.

In principle, reliability-based in-service inspection planning for corrosion and fatigue crack detectioncan be summarized as the following:

Inspection of corrosion and fatigue defects;

Statistical analysis of inspection data and determination of probability of detection;

Formulation of the failure criteria in terms of limit state functions;

Probabilistic descriptions of loading;

Structural response analysis;

Probabilistic assessment of structural strength, including stress analysis;

Probabilistic prediction of corrosion and fatigue crack growth;

Calculation of structural reliability considering the inspection events updating;

Evaluation of reliability analysis results including sensitivity study;

Establishment of target reliability and comparison with estimated reliability;

Determination of inspection interval to satisfy the minimum safety requirements.

The reliability-based inspection planning methodology for corrosion and fatigue are similar, and inthe following section, inspection planning for corrosion defects is discussed.

13.1 Inspection Planning for Corrosion Defects

The limit state function for bursting probability calculation may be expressed as:

g(Z) = pcapacity(t) – pload(t)

where

pcapacity(t) = the bursting capacity of the pipe, in which wall-thickness is a function of time.

pload(t) = the annual maximum operating pressure in pipe.

A methodology for reliability-based inspection and replacement planning of pipelines may bedeveloped based on application of methods for structural reliability analysis within the framework ofBayesian decision theory. The corrosion defect size may be initially estimated using a corrosion ratemodel. This initial estimate may be modified based on the outcome of the previous inspections.Applying this approach, both the initial estimate based on corrosion rate model and the observedcorrosion over the experienced service life are incorporated in the model to estimate future corrosiondefects.


A P P E N D I X 3 Risk Management

CONTENTS1 Hazard Identification ........................................................... 185

3 Criticality Ranking ............................................................... 185

5 Risk Estimation ................................................................... 186

5.1 Frequency Analysis .............................................................. 186

5.3 Consequence Analysis......................................................... 186

7 Human and Organizational Factors.................................... 186

7.1 Quality Assurance ................................................................ 187


A P P E N D I X 3 Risk Management

The objectives of risk analysis are to identify and quantify all reasonably expected hazards to Health,Safety and Environment in design, construction, installation and operation of a pipeline. Results ofrisk analyses can be used in a decision-making process and can aid in localizing the most beneficialrisk-reduction measures.

Risk Management is a management decision making process that includes the identification andanalysis of risks, evaluation of alternative measures to control risks and subsequent assessment ofperformance.

A risk analysis is to be performed, at least at an overall level, to identify critical scenarios that mayjeopardize the safety and reliability of a pipeline system. Other methodologies for identification ofpotential hazards are failure mode and effect analysis, and hazard and operability studies.

Special attention is to be given to areas close to installations or shore approaches where there isfrequent human activity, and thus a greater likelihood for consequence and damage to the pipeline.This also includes areas where pipelines are installed parallel to existing pipelines.

1 Hazard IdentificationAny hazard that is found to introduce risk into the pipeline system, and is also deemed to be withinthe stated outline of the risk analysis, is to be identified and discussed to the level of detail required bythe risk analysis.

Three methods can be used for the identification of hazards:

Reviewing historical data and past experience of similar circumstances;

Employing structured methods, such as hazard and operability studies and failure modes andeffects analysis;

Utilizing methods that provide a logical pathway to translate different release or initiatingevents into possible outcomes, such as event tree analysis and fault tree analysis.

3 Criticality RankingBy definition, risk is increased when either the probability of the event increases or when themagnitude of the consequence increases. To provide an indication of the criticality ranking, thefollowing factors are assessed:

Annual probability and scale of release incidents;

Probability of casualty per release incident;

Number of potential casualties per release incident;

Potential extent of environmental damage per release incident.

Appendix 3 Risk Management A3


5 Risk Estimation

Risk estimation involves combining the results of frequency and consequence analyses to produce ameasure of the risk. The appropriate method is dependent upon the objectives of the risk analysis.Methods that can meet specific objectives include:

Risk matrix methods, in which frequency and consequences are expressed in qualitative termsand combined in a two-dimensional matrix;

Risk index methods, in which points are assigned for specific characteristics related tofrequency and consequences and are combined according to arithmetical rules;

Quantitative risk analysis methods, in which frequency and consequences are estimatedquantitatively and combined on an arithmetical or statistical basis.

Outputs from matrix or index methods provide a relative measure of risk and can be used to provide aqualitative or semi-qualitative analysis of risk. Quantitative risk estimates provide absolute measuresof risk by combining numerical estimates of frequencies, probabilities and consequence in amathematically rigorous fashion.

5.1 Frequency Analysis

The purpose of frequency analysis is to determine the likelihood of the occurrence of the identifiedhazardous events. The frequency of failure may be expressed qualitatively or quantitatively,dependent on the objectives of the risk analysis. It is expressed quantitatively on a collective basis(failures per year) or on a linear basis (failures per kilometer per year).

Approaches available for frequency analysis include:

Analysis of historical incident data;

Fault and event tree analysis;

Mathematical modeling of failure rates (i.e. Structural Reliability Analysis);

Judgement of experienced and qualified engineering and operating personnel based on knownconditions;

Reliability analysis.

5.3 Consequence Analysis

The purpose of consequence analysis is to estimate the severity of adverse effects on people, property,the environment, or combinations thereof. Consequence analyses predict the magnitude and relatedprobability of effects resulting from such events as release of toxic or flammable fluids. Knowledge ofthe release mechanism and the subsequent behavior of the released material enables qualitative orquantitative estimates to be made of the effects of the release at any distance from the source for theduration of exposure.

7 Human and Organizational FactorsThe past record of problems with offshore systems clearly indicates that significant contributors tocritical deficiencies in the quality of these systems are human and organizational factors neglectedduring design and operation. It is therefore necessary to identify the factors influencing these criticaldeficiencies.

Human and organizational factors of any activity that involves human activities are subject to theresults of human influences. These are influences that have both positive and negative impacts ofvarying degrees.

Appendix 3 Risk Management A3


7.1 Quality Assurance

The safety format within this Guide requires that gross errors (human errors) are to be controlled byrequirements for organization of the work, competence of persons performing the work, verificationof the design, and quality assurance during all relevant phases.

For the purpose of this Guide, it is assumed that the Owner of a pipeline system has established aquality objective. In both internal and external quality related aspects, the Owner should seek toachieve the quality level of products and services intended in the quality objective. Furthermore, theOwner is to provide assurance that intended quality is being or will be achieved.


A P P E N D I X 4 Assessment of Corrosion, Dentand Crack-like Defects

CONTENTSSECTION 1 Corrosion Defect Assessment ............................. 191

1 Scope of the Assessment .................................... 193

3 Corrosion Defect Inspection................................. 193

5 Corrosion Defect Measurements ......................... 194

7 Corrosion Defect Growth...................................... 194

9 CO2 Corrosion Rate Estimate.............................. 195

11 Maximum Allowable Operating Pressure forCorroded Pipes .................................................... 195

13 Maximum Allowable Moment ............................... 196

SECTION 2 Maximum Allowable Operating Pressure forDented Pipes ......................................................... 201



S E C T I O N 1 Corrosion Defect Assessment

CONTENTS1 Scope of the Assessment ................................................... 193

3 Corrosion Defect Inspection............................................... 193

5 Corrosion Defect Measurements........................................ 194

7 Corrosion Defect Growth .................................................... 194

9 CO2 Corrosion Rate Estimate............................................. 195

11 Maximum Allowable Operating Pressure for CorrodedPipes .................................................................................... 195

13 Maximum Allowable Moment.............................................. 196

13.1 Calculation 1:........................................................................ 197

13.3 Calculation 2:........................................................................ 197



S E C T I O N 1 Corrosion Defect Assessment

This Appendix defines strength criteria that may be used for corrosion allowance design andassessment of corroded and dented pipes and girth weld defects.

1 Scope of the Assessment

The scope of the assessment includes:

Proper characterization of defects by thickness profile measurements;

An initial screening phase to decide whether detailed analysis is required, or whether fitnessfor service is to be considered;

Detailed assessment phase:

Check burst limit state (allowable versus maximum internal service pressure).

Check collapse limit state (allowable versus maximum external service pressure,bending moment, and axial load).

Check adequacy of residual corrosion allowance for remaining service life.

Other checks, e.g., residual fatigue life, particularly if cracks are detected withindefects.

Updated inspection and maintenance program.

3 Corrosion Defect InspectionThe pipe is to be inspected, if applicable, for defects due to corrosion and consideration is to be givento the uncertainties in corrosion rate and measurement accuracy. These uncertainties may be modeledby a probabilistic method.

Initially, inspection intervals may be set as 3 years for oil and water lines and 6 years for dry gas lines.However, the optimum inspection intervals may be selected using reliability-based inspectionplanning techniques. The reliability-based inspection planning procedure is to estimate the corrosionrate in the line and identify all the defects that would fail the strength requirements before nextinspection.

Appendix 4 Assessment of Corrosion, Dent and Crack-like DefectsSection 1 Corrosion Defect Assessment A4-1


5 Corrosion Defect Measurements

The actual size and shape of the corrosion defect is to be defined by an adequate number of measuredthickness profiles. These measurements are to be performed in accordance with Section 5.3 of APIRP 579 or equivalent.

The assessment of a single isolated defect is to be based on a critical profile defined by the largestmeasured characteristic dimensions of the defect (e.g., depth, width, length) and properly calibratedsafety/uncertainty factors, in order to account for uncertainties in the assessment and thicknessmeasurements. See API RP 579 Section 4.3 for guidance on extracting the critical profile frommeasured thickness profiles.

If several corrosion defects inside a relatively small area have been detected during an inspection,appropriate determination of defect interaction is to be conducted, accounting for the followingfactors:

Angular position of each defect around circumference of the pipe;

Axial spacing between adjacent defects;

Internal or external defects;

Length of individual defects;

Depth of defects;

Width of defects.

A distance equivalent to the nominal pipe wall thickness may be used as a simple criterion ofseparation for colonies of longitudinally oriented pits separated by a longitudinal distance or parallellongitudinal pits separated by a circumferential distance.

For longitudinal grooves inclined to pipe axis:

If the distance x, between two longitudinal grooves of length L1 and L2, is greater than eitherof L1 or L2, then the length of corrosion defect L is L1 or L2, whichever is greater. It can beassumed that there is no interaction between the two defects;

If the distance x, between two longitudinal grooves of length L1 and L2, is less either of L1 andL2, it is to be assumed that the two defects are fully interacted and the length of the corrosiondefect L is to be taken as L = L1 + L2 + x.

7 Corrosion Defect GrowthThe corrosion defect depth d after the time T of operation, may be estimated using an averagecorrosion rate Vcr:

d = d0 + Vcr⋅T

where d0 is defect depth at present time.

The defect length may be assumed to grow in proportion with the depth, hence:

⋅+=

00 1

d

TVLL cr

where L and L0 are defect lengths at the present time and the time T later.

The corrosion rate is to be based on relevant service data or laboratory tests.



9 CO2 Corrosion Rate Estimate

CO2 corrosion rates in pipelines made of carbon steel may be evaluated using industry acceptedequations that preferably combine contributions from flow independent kinetics of the corrosionreaction at the metal surface, with the contribution from flow dependent mass transfer of dissolvedCO2.

The corrosion rate Vcr, in mm/year, can be predicted by:

mr

cr

VV

V11

1

+=

where Vr is the flow independent contribution, denoted the reaction rate, and Vm is the flow dependentcontribution, denoted the mass transfer rate.

The reaction rate Vr can be approximated by:

)COlog(58.0273

111993.4)log( 2p

TV

mpr ⋅+

+−=

where the temperature Tmp is to be given in °C, and the partial pressure pCO2 of CO2 in bar. The

partial pressure pCO2 can be found by:

pCO2 = nCO2 ⋅ popr

where nCO2 is the fraction of CO2 in the gas phase, and popr is the operating pressure in bar.

The mass transfer rate Vm is approximated by:

22.0

8.0

45.2 pCOd

UVm ⋅⋅=

where U is the liquid flow velocity in m/s and d is the inner diameter in meters.

11 Maximum Allowable Operating Pressure for CorrodedPipes

All defects deeper than 0.8 times the wall thickness are to be repaired. For less severe defect depthsASME B31G or the following criteria may be applied to estimate the maximum allowable operatingpressure for pipelines and risers with a single corrosion defect:

( )

( )28.011

12

5.0

DtLt

dt

d

D

tSMTSSMYSpMAOP burst

+−

−

+⋅=⋅≤ ηη

where

MAOP = maximum allowable operating pressure

pburst = internal overpressure at burst


t = wall thickness measurement



d = depth of corrosion defect, not to exceed 0.8 × t

L = length of corrosion defect

SMYS = Specified Minimum Yield Strength in hoop direction

SMTS = Specified Minimum Tensile Strength in hoop direction

η = usage factor which is to be taken in accordance with A4/Table 1

TABLE 1Usage Factors for Hoop Stress Criteria

Safety ClassUsageFactor Low Normal High

η 0.76 0.72 0.63

Note:1 Safety classes are in accordance to Appendix 1, Section 3.

2 Load factors and condition load factors are in accordance to A1-2/3.

13 Maximum Allowable Moment

Local buckling may occur due to excessive combined pressure, longitudinal force and bending. Thefailure mode will be a combination of local yielding and flattening/local buckling. The failure modemainly depends on the diameter to wall thickness ratio (D/t), load condition, and local imperfectionsin material and geometry. This section gives the maximum allowable bending moment for pipes witha local corrosion defect. The formulas in this section are applicable to diameter to thickness ratio inbetween 10 and 60. For pipes of larger D/t ratio, the use of the moment criterion is subjected to theapproval of the Bureau.

The maximum allowable bending moment for local buckling of corroded pipes, valid for bothinternal- and external- overpressure, can be expressed as given below. The bending strength is to befound by both calculations 1 and 2, after which the lowest value is to be used as the maximumallowable design moment.

The maximum allowable bending moment for local buckling can be found by:

( ) ( ) ( ) ( ) ( )

−−+−+

−−=

22

22

22

1 11sin15.011sinP

p

P

pk

P

pMM

RPRPRPC

RMall η

αδη

αβη

αψδγη

where the angle to the plastic neutral axis is given by:

( ) ( ) ∆δ

βπδ

βδπψ5

1

4

13

2

1

2

1 kk −−+−+= ,

( )2

211

−−

−

=

P

p

P

p

F

F

RP

RPRF

C

ηα

ηα

ηγ

∆

For grooves on the inner side of the pipe wall:

2

21 11,11

+

−=

+

−=

D

d

t

dk

D

d

t

dk



For grooves on the outer side of the pipe wall:

2

21 11,11

−

−=

−

−=

D

d

t

dk

D

d

t

dk

The strength anisotropy factor is given by:

F

pD ⋅⋅=4

2πα

For extreme pressure and/or axial force conditions, it is advised that this factor be verified by finiteelement analysis.

13.1 Calculation 1:

If ( )( )∆

∆πβ+−

+≥

1

1

1 1k

then δ1 = 1, δ2 = -1, δ3 = 1, δ4 =1, δ5 = -1

else δ1 = k1, δ2 = 1, δ3 = -1, δ4 = k1, δ5 = -k1

13.3 Calculation 2:

If ( )( )∆

∆πβ−+

+≥

1

1

1 1k

then δ1 = -1, δ2 = 1, δ3 = 1, δ4 =1, δ5 = 1

else δ1 = -k1, δ2 = -1, δ3 = -1, δ4 = k1, δ5 = k1

where

MAll = allowable bending moment

p = pressure acting on the pipe

F = longitudinal force acting on the pipe


t = wall thickness

d = defect depth

ψ = angle from bending plane to plastic neutral axis

ki = constant

α = strength anisotropy factor

β = half the defect width

δi = constants

γC = condition load factor

ηR = strength usage factor, in accordance with A4/Table 2.



The moment M , which is the moment capacity in pure bending, may be calculated as:

tDSMYSt

DM ⋅⋅⋅

⋅−= 20015.005.1

where


t = wall thickness

SMYS = specified Minimum Yield Strength in longitudinal direction

The longitudinal force F may be estimated as:

F =0.5(SMYS + SMTS)(π – (1 – k1)β)Dt

where


t = wall thickness

β = half of the corrosion defect angle

SMYS = Specified Minimum Yield Strength in longitudinal direction

SMTS = Specified Minimum Tensile Strength in longitudinal direction

k1 = constant given in A4-1/13

The pressure p is for external overpressure conditions equal to the pipe collapse pressure and may becalculated based on:

020

223 =+

+−− pe

corpepe ppp

t

Dfpppppp

where

pe =3

2 )1(

2

− D

tE cor

ν

pp =D

tSMYS cor

fab2

η

tcor = minimum measured wall thickness including proper reduction factor accountingfor inaccuracy in measurement method

f0 = initial out-of-roundness (1), (Dmax – Dmin)/D


E = Young’s Module


kfab = fabrication de-rating factor given in 3-4/7

Notes:1 Out-of-roundness caused during the construction phase is to be included, but not flattening due to

external water pressure or bending in as-laid position. Increased out-of-roundness due to installation andcyclic operating loads may aggravate local buckling and are to be considered. Here it is recommendedthat out-of-roundness, due to through life loads, be simulated using finite element analysis.



For internal overpressure conditions, the pressure p is equal to the burst pressure, which may befound as:

( )

( )28.011

125.0

DtLt

dt

d

D

tSMTSSMYSp

+−

−

+=

where


t = wall thickness measurement

d = depth of corrosion defect, not to exceed 0.8 × t

L = measured length of corrosion depth


SMTS = Specified Minimum Tensile Strength in hoop direction

Load factors and condition load factors are to be taken in accordance with A1-2/3, and resistancefactors ηR are listed in A1-4/Table 1.



S E C T I O N 2 Maximum Allowable OperatingPressure for Dented Pipes

The determination of maximum allowable operating pressure for a dented pipe with cracks is given inthe following.

Maximum allowable operating pressure may be calculated as:

ησ ⋅⋅⋅=D

tP 2

where the usage factor η may be taken as 0.72 and the critical stress at failure σ is given by:

σ⋅⋅⋅⋅π−⋅

πσ⋅

=σ −22

21

8expcos

2

p

matp

aY

K

The plastic failure stress σp of may be taken as:

2)(8.01 DtL

at

atfp

+−

−⋅σ=σ

where

D = average pipe diameter

t = pipe wall thickness

L = length of dent

a = maximum depth of pipe wall thickness defect

and σf is the flow stress, here defined as the mean value of Specified Minimum Yield and Tensile

Strength.

Pipe toughness is measured in terms of the Charpy energy Cv. This measure is a qualitative measurefor pipe toughness and has no theoretical relation with the fracture toughness parameter, Kmat.Therefore it is necessary to use an empirical relationship between Kmat and Cv which can be taken as:

Appendix 4 Assessment of Corrosion, Dent and Crack-like DefectsSection 2 Maximum Allowable Operating Pressure for Dented Pipes A4-2


( )6.1710002 −= Vmat CA

EK

where

Kmat = material toughness (N/mm3/2)

Cv = Charpy energy (J)

E = Young’s modulus (N/mm2)

A = section area for Charpy test (mm2), normally A = 80 mm2

The geometry function Y can be expressed as:

⋅⋅+

⋅−⋅=

t

DH

D

D

Q

FY dd 1.58.11

where

Dd = depth of dent

and geometry correction factors Q, F and H are given by the following:

65.1

464.11

+=

c

aQ for 1≤

c

a

where

c = half length of dent

wgfft

aM

t

aMMF φ

+

+=

4

3

2

21

where

M1 =c

a09.013.1 −

M2 = ( )ca /2.0

89.054.0

++−

M3 = ( )24

114/65.0

15.0

−+

+−

c

a

ca

g = ( )22

sin135.01.01 φ−

++

t

a

where

φ = parametric angle of the elliptical-crack

The function fφ, an angular function from the embedded elliptical-crack solution is:

4/1

222

sincos

φ+φ

=φ c

af

Appendix 4 Assessment of Corrosion, Dent and Crack-like DefectsSection 2 Maximum Allowable Operating Pressure for Dented Pipes A4-2


The function fw, a finite-width correction factor is:

2/1

sec

⋅=

t

a

D

cf w

The function H has the form:

( ) φ−+= pHHHH sin121

where

p =

+

+

t

a

c

a6.02.0

H1 =

−

−

t

a

c

a

t

a11.034.01

H2 =2

211

++

t

aG

t

aG

and

G1 =

−−

c

a12.022.1

G2 =5.175.0

47.005.155.0

+

−

c

a

c

a


A P P E N D I X 5 References by Organization

Standards/codes acceptable to the Bureau are not limited to the following references.

When updates of the referenced documents are available these are as far as possible to be used.

Which standards/codes to be followed during design, manufacturing, transportation, storage,installation, system testing, operation, amendment, decommission etc. is generally to followinternational agreements and be agreed upon between Local Authorities, Owners, Operators, Clientsand Contractors.

The Bureau claims the right to reject documents, procedures etc. where standards/codes are judgedmisused e.g. by “shopping around”.

ABS ABS Plaza, 16855 Northchase Drive,American Bureau of Shipping Houston, TX 77060, USA

Code No. Year/Edition Title

1996 Rules for Building and Classing Single Point Moorings

1997 Rules for Building and Classing Offshore Installations

2000 Guide for Building and Classing Floating Production Installations

2001 Rules for Building and Classing Steel Vessels

AGA 400N Capitol Street NWAmerican Gas Association Washington, DC 20001, USA


PR-3-805 1989 A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe

L51698 1993 Submarine Pipeline On-Bottom, Vol. I :Stability Analysis and DesignGuidelines

AISC One East Wacker Drive, Suite 3100American Institute of Steel Construction Chicago, IL 60601-2001, USA


1989 ASD Manual of Steel Construction, 9th Edition

Appendix 5 References by Organization A5


API 1220 L Street, NWAmerican Petroleum Institute Washington, DC 20005-4070, USA


SPEC 5L 2000 Line Pipe

SPEC 5LC 1998 CRA Line Pipe

SPEC 5LD 1998 CRA Clad or Lined Steel Pipe

SPEC 6A 1999 Wellhead and Christmas Tree Equipment

SPEC 6D 1996 Pipeline Valves (Gate, Plug, Ball, and Check Valves)

SPEC 17D 1992 Subsea Wellhead and Christmas Tree Equipment

STD 600 1997 Steel Gate Valves—Flanged and Butt-Welding Ends, Bolted

and Pressure Seal Bonnets,

STD 1104 1999 Welding of Pipelines and Related Facilities,

RP 2A-WSD 2000 Planning, Designing, and Constructing Fixed Offshore Platforms – WorkingStress Design

RP 2N 1995 Planning, Designing, and Constructing Structures and Pipelines for ArcticConditions

RP 2RD 1998 Design of Risers for Floating Production Systems (FPS’s) and Tension-LegPlatforms (TLP’s)

RP 2SK 1996 Design and Analysis of Stationkeeping Systems for Floating Structures

RP 2T 1997 Planning, Designing and Constructing Tension Leg Platforms

RP 5L1 1996 Railroad Transportation of Line Pipe

RP 5LW 1996 Transportation of Line Pipe on Barges and Marine Vessels

RP 14G 2000 Fire Prevention and Control on Open Type Offshore Production Platforms.

RP 579 2000 Fitness-For-Service

RP 1111 1999 Design, Construction, Operation, and Maintenance of Offshore HydrocarbonPipelines and Risers

ASME 22 Law Drive, P.O. Box 2900American Society of Mechanical Engineers Fairfield, New Jersey 07007-2900, USA


B16.5 1996 Pipe Flanges and Flanged Fittings

B16.9 1993 Factory-Made Wrought Steel Buttwelding Fittings

B16.11 1996 Forged Steel Fittings, Socket-Welding and Threaded

B16.20 1998 Metallic Gaskets for Pipe Flanges: Ring-Joint, Spiral-Wound, and Jacketed

B16.25 1997 Buttwelding Ends

B16.34 1996 Valves-Flanged, Threaded, and Welding End

B31G 1991 Manual for Determining the Remaining Strength of Corroded Pipelines: Asupplement to B31

B31.4 1998 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids

B31.8 1999 Gas Transmission and Distribution Piping Systems

Boiler andPressure VesselCode

1998 Section VIII: Pressure Vessels – Divisions 1 and 2

Section IX: Welding and Brazing Qualifications

ASNT 1711 Arlingate LaneAmerican Society for Nondestructive Testing Columbus, OH 43228-0518, USA


SNT-TC-1A 1996 Personnel Qualification and Certification – Recommended Practice



ASTM 100 Barr Harbor DriveAmerican Society for Testing and Materials West Conshohocken, Pennsylvania, 19428-2959,

USA


A790/

A790M-00e1

2001 Standard Specification for Seamless and Welded Ferritic / Austenitic StainlessSteel Pipe

B861-00 2000 Standard Specification for Titanium and Titanium Alloy Seamless Pipe

B862-99 1999 Standard Specification for Titanium and Titanium Alloy Welded Pipe

AWS 550 N. W. LeJeune Road ,American Welding Society Miami, FL 33126, USA


D1.1 2000 Structural Welding Code-Steel

D3.6M 1999 Specification for underwater welding

BSI 2 Park StreetBritish Standards Institute London W18 2BS, England


BS 4515-1 2000 Specification for welding of steel pipelines on land and offshore. Carbon andcarbon manganese steel pipelines

BS 4515-2 1999 Specification for welding of steel pipelines on land and offshore. Duplexstainless steel pipelines

BS 7910 1999 Guide on methods for assessing the acceptability of flaws in metallic structures

BS 8010-3 1993 Code of practice for pipelines. Pipelines subsea: design, construction andinstallation

CSA 178 Rexdale BoulevardCanadian Standard Association Toronto, ON, M9W 1R3, Canada


Z662-99 1999 Oil and Gas Pipeline Systems

HSEHealth and Safety Executive UK


Z662-99 1990 Offshore Installations: Guidance on Design, Construction and Certification

ISO Case Postale 65International Organization of Standards CH 1211 Geneve 20, Switzerland


ISO 3183-1 1996 Petroleum and natural gas industries- Steel pipe for pipelines-Technical deliveryconditions, Part 1: Pipes of Requirement Class A

ISO 3183-2 1996 Petroleum and natural gas industries- Steel pipe for pipelines-Technical deliveryconditions, Part 2: Pipes of Requirement Class B

ISO 3183-3 1999 Petroleum and natural gas industries- Steel pipe for pipelines-Technical deliveryconditions, Part 3: Pipes of Requirement Class C

ISO 11484 1994 Steel tubes for pressure purposes- Qualification and certification of non-destructive testing (NDT) personnel



MSS 127 Park Street, NE.Manufacturers Standardization Society Vienna, VA 22180, USAof the Valve and Fittings Industry, Inc.


SP-44 1996 Steel Pipe Line Flanges

SP-75 1998 Specification for High Test Wrought Butt Welding Fittings

NACE International 1440 S. Creek DriveHouston, TX 77084-4906, USA


MR0175 2000 Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment

RP0176 1994 Corrosion Control of Steel, Fixed Offshore Platforms Associated withPetroleum Production

TM0177 1996 Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking andStress Corrosion Cracking in H2S Environments

TM0284 1996 Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking

abs64-guide for building and classing-subsea pipeline systems and risers

Documents

classification of design

installation of pipelines

design of metallicrisers

conditions of classification

design loads

new methods of design

pipeline rectification

construction andtesting