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Integrity Management of Risers from Floating Production Systems

API RECOMMENDED PRACTICE 2RIM FIRST EDITION, SEPTEMBER 2019

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Special Notes

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API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to ensure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict.

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Publisher, API Publishing Services, 200 Massachusetts Avenue, NW, Washington, DC 20001.

Copyright © 2019 American Petroleum Institute


Foreword

Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.

The verbal forms used to express the provisions in this document are as follows.

Shall: As used in a standard, “shall” denotes a minimum requirement in order to conform to the standard.

Should: As used in a standard, “should” denotes a recommendation or that which is advised but not required in order to conform to the standard.

May: As used in a standard, “may” denotes a course of action permissible within the limits of a standard.

Can: As used in a standard, “can” denotes a statement of possibility or capability.

This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard. Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 200 Massachusetts Avenue, NW, Washington, DC 20001. Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director.

Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A one-time extension of up to two years may be added to this review cycle. Status of the publication can be ascertained from the API Standards Department, telephone (202) 682-8000. A catalog of API publications and materials is published annually by API, 200 Massachusetts Avenue, NW, Washington, DC 20001.

Suggested revisions are invited and should be submitted to the Standards Department, API, 200 Massachusetts Avenue, NW, Washington, DC 20001, [email protected].

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Contents

Page

1 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2 Normative References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

3 Terms, Definitions, and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.1 Terms and Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.2 Abbreviations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

4 Integrity Management Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64.2 Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.3 Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

5 Riser Integrity Management Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95.2 Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95.3 Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115.4 Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145.5 Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155.6 Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

6 Inspection and Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166.2 Riser Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176.3 Riser Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

7 Riser Assessment Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227.2 Assessment Initiators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 237.3 Assessment Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 237.4 Assessment Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

8 Assessment Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 298.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 298.2 Sensitivities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 298.3 Functionality. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308.4 Burst . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 328.5 Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 338.6 Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 348.7 Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 358.8 Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 388.9 Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 398.10 Sealability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

9 Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 419.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 419.2 TTR Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 419.3 SCR Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 429.4 Hybrid Riser Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

10 Risk Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4310.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4310.2 Exposure Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

v


3 Likelihood Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

11 Riser Decommissioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4511.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4511.2 Decommissioning Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Annex A (informative) Assessment Method Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Annex B (informative) Commentary Additional Information and Guidance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

FiguresPhysical Interfaces between API IM Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

1 IM Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Risk Categorization Matrix Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 Primary Geometric Parameters of Most Deformed Cross Section of a Dent . . . . . . . . . . . . . . . . . . . . . . . 34A.1 Inspection Grid for Wall Thickness Measurements at LWL Area. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49A.2 Longitudinal CTP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Tables1 Riser In-service Key Performance Indicators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212 Riser Assessment Initiators and Triggers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24A.1 Measured Wall Thicknesses in Local Thin Area (LTA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49B.1 Riser Monitoring Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

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Introduction

This recommended practice (RP) is one of three additions to API’s portfolio of offshore floating structures standards that address integrity management (IM) of floating systems (API 2FSIM), mooring systems (API 2MIM), and riser systems (API 2RIM).

This RP is intended to be used by owners and engineers in the development, implementation, and delivery of a process to maintain system integrity of floating production systems (FPSs), including tension leg platforms (TLPs). The specifications, procedures, and guidance provided herein are based on internationally recognized industry standards and on global industry best practices.

API’s existing suite of RPs such as API 2FPS, API 2T, API 2SK, API 2RD, and API 2SIM address several aspects of life cycle integrity management expectations, and the three new standards add to that suite by capturing experiences from owners, operators, integrity management specialists, recognized classification societies (RCSs), and regulators, establishing a common framework for IM for FPSs. Figure Intro 1 pictorially depicts the interfaces between the hull and mooring and risers for various types of FPSs and the IM standard that addresses the specific systems.

Physical Interfaces between API IM Standards

Tension LegPlatform Spar FPSO

Risers

Mooring

Hull

Topsides

Implementation of effective integrity management for floating systems requires an understanding of the interfaces between the hull, mooring, and risers and how they translate to stewardship of IM activities in the field. The new standards have been developed with the objective of recognizing and identifying key interfaces, and they emphasize the criticality of a systems level approach.

By having a consistent systems level approach and by pursuing a risk-based framework to develop, evaluate, plan, and implement an integrity management program for a floating system, the user can tailor the IM program around the unique design drivers, in-service and operating conditions while conforming to the owner’s organizational safety, health and environment risk management policies and regulatory requirements.

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1

Integrity Management of Risers from Floating Production Systems

1 Scope

This recommended practice (RP) provides guidance for the integrity management (IM) of risers connected to a permanent floating production system (FPS) used for the drilling, development, production, and storage of hydrocarbons in offshore areas.

A riser is typically part of a larger subsea system extending from a wellhead, tree, manifold, template, or other structure on the seabed, to a boarding valve or pig trap on the host platform’s topsides. This RP addresses the integrity management of the dynamic portion of the riser system.

For the purposes of this RP, a riser has a top boundary that is somewhere at or above the point where it transfers load to the platform structure, and it has a lower boundary where it transfers load into a foundation, which could be a wellhead, pipeline, or subsea structure.

For a top-tensioned riser (TTR), the top boundary would typically be the tensioner system hang-off point, and the bottom boundary would be the wellhead. For a steel catenary riser (SCR), the top boundary would typically be the stress joint or flexible joint. Some unusual configurations such as pull-tube SCRs merit special consideration. The top boundaries of a flexible or hybrid riser are typically a flanged connection to the riser end fitting at the top of an I-tube or J-tube, and a bend stiffener at the bottom of a I-tube or J-tube.

The IM of the structural support for a riser on the host platform is in the scope of API 2FSIM, although some hybrid configurations, such as pull tubes, can require overlapping riser and structural IM.

For risers structurally connected to the platform below the topsides, hull piping can be structurally clamped to the hull up to a boarding valve or pig launcher at the topsides. This is intended to be considered as part of the riser in terms of IM, although it also has structural elements addressed in API 2FSIM.

The scope of this RP includes:

— structural components of the riser;

— riser top hang-off assembly (i.e. stress joint, flexible joint, tensioner system/air can, bend stiffener);

— appurtenances attached to the riser that are critical to its integrity, including VIV suppression devices and buoyancy modules used to support the riser in any capacity;

— corrosion protection systems;

— insulation;

— other components in the load path or supporting the riser.

The scope of this RP specifically does not include:

— structural support for the riser on the host platform (i.e. riser porch, pull tube, tensioner support structure);

— wellhead or subsea structure at the lower end of the riser;

— valves (other than the mechanical design if they are in the dynamic load path);

— risers connected to mobile offshore drilling units (MODUs) or fixed platforms.

NOTE However, the interface of the riser with these components is important to the IM of the riser system.


2 API RECOMMENDED PRACTICE 2RIM

Specific recommendations are provided for the inspection, monitoring, evaluation of damage, fitness-for-service assessment, risk reduction, mitigation planning, and decommissioning of risers. This RP incorporates and expands on the integrity management recommendations found in API 2RD, API 17B, and API 17L2.

2 Normative References

This document contains no normative references. For a list of documents and other publications associated with API 2RIM, see the Bibliography.

3 Terms, Definitions, and Abbreviations

For the purposes of this document, the following terms and definitions apply.

3.1 Terms and Definitions

For the purposes of this document, the following terms and definitions apply.

3.1.1 anomalyAn observation or finding indicating the possibility that a certain parameter could be outside an acceptable design or performance threshold.

3.1.2 assessmentA technical review process triggered by an assessment initiator (as identified during an evaluation) to demonstrate that a system or structure is fit-for-service or to determine the need for risk reduction.

3.1.3 assessment initiatorsChanges in riser condition or operating experience, such as storms, which require an existing riser to undergo an assessment to demonstrate fitness-for-service.

3.1.4 buoyancy moduleA buoyant device secured to a riser to provide supplemental buoyancy.

NOTE Such devices are most commonly constructed from syntactic foam but can also have other structural forms.

3.1.5 catenary riserA riser that is suspended in a catenary shape from near-vertical at the host platform to horizontal on the seabed after the touch-down point, typically constructed from steel line pipe or flexible pipe.

NOTE Supplemental buoyancy can be attached to portions of its length in some instances, forming a “wave” in the riser shape.

3.1.6 condition assessmentThe process of gathering information on a riser’s present condition to perform a fitness-for-service assessment.

3.1.7 defectAn imperfection or flaw in a component of an existing riser.

NOTE As used in this RP, the term “defect” does not necessarily denote that the riser is not fit-for-service.


INTEGRITY MANAGEMENT OF RISERS FROM FLOATING PRODUCTION SYSTEMS 3

3.1.8 degradationThe reduction in the ability of a component to provide its intended service.

3.1.9 design lifeThe time period assumed for defining various design parameters such as corrosion allowance and fatigue life.

3.1.10 evaluationAn engineering review of integrity data, using engineering judgment, risk assessment, calculations, analysis, or other methods to identify anomalous conditions (i.e. assessment initiator) and determine whether additional detailed assessment or risk reduction is required to demonstrate fitness-for-service.

NOTE An evaluation can also consist of an engineering review of proposed changes to the riser to determine their significance on fitness-for-service.

3.1.11 extreme eventA design metocean, seismic, and/or ice condition, with a low probability of exceedance, that a riser can be subjected to during its operational life.

3.1.12 failureInsufficient strength or inadequate serviceability of a system or component to fulfill its performance requirements.

3.1.13 fitness-for-serviceA demonstration that a riser has adequate integrity for the intended operating conditions while maintaining design functionality.

3.1.14 flexible riserA catenary riser constructed from flexible pipe.

3.1.15 floating production systemA permanently moored floating platform that serves as the host for the risers under consideration (same as “host platform”).

3.1.16 host platformSame as floating production system.

3.1.17 hybrid riserA riser that consists of two or more types of risers combined, typically with some sort of buoyancy supporting part of the riser and the remainder connecting to the host platform.

3.1.18 in-serviceThe condition that characterizes a riser that has been commissioned and placed in operation.

3.1.19 inspectionA specific visual or nondestructive examination performed for collecting data required in evaluation of a riser’s integrity.



3.1.20 insulationAn external coating that provides insulation to the riser, which can also be buoyant in sea water and hence have the same effect as buoyancy modules.

3.1.21 integrity dataInformation on the design, condition, and operation of a riser system.

3.1.22 life extensionThe procedure of demonstrating the extension of the operational life of a riser beyond the life specified during the original design and/or as originally permitted.

3.1.23 management of changeA system for review and approval of changes in processes, procedures, or physical components prior to implementation of the change.

NOTE This usually includes assessment of risk, economic, and schedule implications.

3.1.24 mechanical damageA defect type that includes physical damage such as dents, gouges, wear, or other unanticipated plastic deformation.

3.1.25 mitigationActions taken to limit negative consequences or to reduce the likelihood of occurrence of an event or condition.

3.1.26 operatorThe person, firm, corporation, or other organization employed by the owners to operate a floating production system.

3.1.27 original design criteriaDesign basis and design codes used in the original riser design.

NOTE The design criteria include reference codes, metocean conditions, analysis methods, safety factors, and original design assumptions.

3.1.28 ownerA party who owns physical infrastructure assets (risers) and/or a party who owns capacity rights in those physical assets but does not own the asset itself.

3.1.29 performance criteriaCriteria used in a fitness-for-service assessment of a riser system.

3.1.30 prior exposureThe historical exposure of a riser to the design conditions.



3.1.31 repairThe work necessary to restore a deteriorated structure or system to a condition deemed fit-for-service.

3.1.32 retrievable riserA riser that is designed to be deployed and retrieved multiple times as part of its intended service, such as a drilling riser (i.e. a riser for which dry inspection could be considered in the IM plan).

3.1.33 riserA pipe or system of pipes that spans from the seabed to the host platform and conveys fluids to or from the host platform.

NOTE Riser service includes production, drilling, well completion, water injection, gas injection, gas lift, oil export/import, and gas export/import.

3.1.34 service lifeThe time period between a riser’s installation date and the anticipated end of service.

3.1.35 splash zoneThe area of the riser that is intermittently wet or dry due to wave and tidal actions or change in operating draft.

3.1.36 steel catenary riserA catenary riser constructed from rigid steel pipe.

3.1.37 surveyA general view, examination, or other activities performed for collecting data required in evaluation of system integrity.

3.1.38 vortex-induced motionInline and transverse oscillation of a floating production system in a current induced by the periodic shedding of vortices about the hull of the platform.

3.1.39 vortex-induced vibrationInline and transverse oscillation of a riser in a current induced by the periodic shedding of vortices.

3.2 Abbreviations

BOP blowout preventerCP cathodic protectionCRA corrosion resistant alloyFAT factory acceptance testFEA finite element analysisFM fracture mechanicsFPS floating production systemFPSO floating production, storage, and offloadingILI in-line inspection



IM integrity managementKPI key performance indicatorsLTA local thin areaNDE nondestructive examinationOEM original equipment manufacturerPLET pipeline end terminationPQR procedure qualification recordRBI risk-based inspectionROV remotely operated vehicleRSF remaining strength factorSAF stress amplification factorSCF stress concentration factorSCR steel catenary riserSIT system integration testSLWR steel lazy wave riserSMR strengthening, modification and/or repairSMTS specified minimum tensile strengthSMYS specified minimum yield strengthTTR top-tensioned riserVIM vortex-induced motion (of a host platform)VIV vortex-induced vibration (of a riser)WPS weld procedure specification

4 Integrity Management Overview4.1 General

The purpose of integrity management (IM) is to provide a proactive process for demonstrating the integrity of a riser throughout its life on a fitness-for-service basis. The IM process relies on gathering and collating information on the riser, periodically evaluating the data, and using the evaluation to set a strategy for subsequent inspection and monitoring.

IM of risers consists of the continuous process as illustrated in Figure 1.

IM process for a riser should be used from design through decommissioning to:

— understand, communicate, and manage the in-service structural risk;

— manage the effects of deterioration, damage, changes in service conditions, and accidental overloading;

— establish the framework for inspection planning, maintenance, and/or repair;

— demonstrate that the riser is fit-for-service (or prepare for decommissioning).

Implementing an IM process for risers provides an orderly way of maintaining an appropriate level of inspection and monitoring, ensuring that the riser is operating within its intended ranges, and managing the effects of deterioration and damage. The IM process is founded on risk principles and provides owners a framework for inspection, maintenance, monitoring, and remediation activities to validate the fitness-for-service of a riser for its intended application throughout its service life.


Figure 1—IM Process

DESIGN, FAB,

INSTALL

BASELINE

INSPECTIONSMANAGEMENT

OF CHANGE

Fit for

Service?

Modify, Repair,

Replace?

Assessment

Process

Assessment

Yes

No

Repair

Replace Modify

No

Yes

Initiator

triggered?

Detailed work scope for

inspection activities

and offshore execution

Managed system for

the archival and

retrieval of IM data and

other pertinent records

Evaluation of the

mechanical integrity

and fitness for service;

development of

remedial actions

Overall inspection

philosophy, strategy,

and criteria for in

service inspection

DATA

PROGRAM

STRATEGY

EVALUATION




Approaches to IM vary depending upon field life, type of riser, type of host platform, service conditions (e.g. internal pressure, temperature, fluid properties), and sophistication of regional infrastructure in which the riser is located. These factors influence the philosophical approach to IM that can vary from a riser involving emphasis on the use of monitoring equipment, to another riser with a preference for the extensive use of inspections. Regardless of the chosen IM approach, the purpose of the IM is to manage the integrity of the riser throughout its service life. The IM process can be used to demonstrate that the risks to riser operations are understood and to prevent and/or mitigate incidents that could result in safety, environmental, or economic consequences to the owner.

Choices are made in the design (e.g. selection of materials, design margins, operating procedures, condition monitoring systems, new or proven technology, robustness of design, redundancy, and fabrication/installation methods) that will influence IM activities during the operations. Implementation of an IM process can benefit from design decisions, such as providing access for inspection and maintenance. Initial IM development begins as part of the riser’s design or reuse, ideally during the riser’s concept and select stages.

The IM process is used to develop an inspection and monitoring program, including scope and frequency that can provide additional information on the condition of the riser. The collected information can be used to understand present and emerging risk from operating the riser and can provide information for determining the ongoing strategy for mitigating the emerging risk. A well-implemented IM process can provide evidence that the riser remains fit-for-service for the operational life of the riser and through to decommissioning.

Throughout the service life of the riser, new data are collected through monitoring activities, scheduled maintenance, scheduled inspections, results of accidental events, or planned changes (e.g. modifications or additions) to the riser. As new data are obtained, the data are subject to engineering evaluation to validate fitness-for-service. Based on the evaluation, adjustments to the strategy plans and program work scopes can be required to confirm fitness-for-service and maintain the riser’s integrity. More detail on each of the elements is provided in Section 5.

4.2 Risk

The owner/operator should adopt risk-based principles for developing IM strategies that consider the present condition of a riser, the likelihood of damage or degradation of the riser, and the potential consequences. The consequences of failure should include the potential for loss of life, as well as undesired environmental and/or economic impacts (e.g. repairs, clean up, replacement, and deferred production).

A risk-based approach recognizes that risers with higher risks could warrant more frequent and more focused inspections than lower risk risers. During the development of an inspection strategy, a risk category can be used for setting inspection intervals and work scopes as part of a risk-based IM strategy.

4.3 Interfaces

This RP is a companion to three other RPs within API that address integrity management:

— API 2SIM, Structural Integrity Management of Fixed Offshore Structures

— API 2FSIM, Floating Systems Integrity Management

— API 2MIM, Mooring Integrity Management

The owner/operator is responsible for understanding and managing the interfaces between the integrity management for each of these interrelated RPs.

For guidelines and recommended practices relating to planning, designing, and constructing risers, including reuse and change-in-use of existing risers, the recommendations in the following industry standards should be considered: API 2RD, API 17B, API 17J, API 17K, API 17L1, API 17L2. Other international standards such as DNV-OS-F201, DNV-RP-F203, DNV-RP-F206 can be considered as well.



5 Riser Integrity Management Process

5.1 General

The owner/operator shall have an IM plan for all risers. The IM plan shall include a process that incorporates the following elements:

— data;

— evaluation;

— assessment;

— strategy;

— program.

A conceptual map of the IM process is shown in Figure 1.

5.2 Data

5.2.1 General

An in-service data management system containing riser IM data shall be established and maintained for the service life of the riser. Data should include information from the original design of the structure, fabrication and installation data, inspection findings, effects of damage and deterioration, riser analyses, overloading, and changes in loading and/or use. In addition, data should include technology development projects or in-service experience of similar structures within industry.

Data fall into the following categories: characteristic, condition, or operating.

In many instances, not all these data might be available. Missing data can affect the evaluation, strategy, and program for the ongoing IM of a riser. Where data are not available or are out of date, surveys of the riser system should be completed to collect the necessary information. It can be more expedient to proceed with an appropriate premise, recognizing the inherent uncertainties and assumptions.

5.2.2 Characteristic Data

The characteristic data describe the as-installed, baseline condition of the riser, or the initial population of the IM data for a riser.

Characteristic data should be collated at the completion of the design, fabrication and installation phases of a project. However, it is recognized that for many older risers, data can be collated well into the operational phase of the riser.

5.2.2.1 The design data should include:

— riser design basis, including design criteria, codes and standards used, pressure, temperature, fluid properties, water depth, seabed topography, geotechnical data, metocean conditions, platform configuration, hang-off details, etc.;

— design calculations, drawings and installation or operating information that affects the design, including insulation and corrosion protection;

— hazard identification and risk assessment work relevant to the design and future IM.



5.2.2.2 The fabrication and installation data should include:

— as-built condition of riser components after factory acceptance test (FAT) and prior to installation, including all specifications, material testing reports, welding procedure qualifications, nondestructive examination (NDE) records, FAT and system integration test (SIT) records, repair and nonconformance records, coating records, as-built information, and vendor data books;

— record of how the riser was assembled and installed, including installation specifications, procedures, activity logs, welding and NDE procedures, coating information, repair and nonconformance records, material tracking (as required), appurtenance records (e.g. buoyancy, VIV suppression), and any other as-built information;

— as-installed data collected from the baseline inspection, documenting any deviations from the design or installation drawings, including appurtenances, as-laid surveys for catenary risers, joint tracking for top-tensioned risers.

5.2.3 Condition Data

The riser condition data represent the present condition of the riser, covering any changes to the characteristic data that occurs during the life of the riser. The following condition data should be collated within a data management system:

— in-service inspection;

— condition monitoring;

— damage evaluation;

— corrosion protection;

— operational incident;

— modifications to the riser;

— modifications to the host FPS that affect the risers.

5.2.4 Operating Data

The riser operating data are comprised of the record of how the riser has been operated, and may include the monitoring and collection of:

— pressure, temperature, flow rates, fluid composition;

— metocean data;

— host FPS motions, offsets, turret rotation (FPSO);

— TTR tensioner settings and annulus pressures;

— other operational monitoring or data recording.

5.2.5 Data Management

IM data collected throughout the life of a riser should be maintained in a data management system. The data should be compiled and updated periodically to provide a record of the riser’s present condition. Data should be collected during inspections as defined by the IM strategy.



The owner/operator should retain detailed and up-to-date records for the service life of the riser. During change of ownership or operatorship, the owner/operator should transfer all riser data to the new operator.

5.3 Evaluation

5.3.1 General

An evaluation of the riser IM data shall be performed throughout the riser’s service life and shall be used to confirm that the riser integrity, mitigation strategies, and established risk levels remain valid. As new information/data are collected, evaluation shall review the new information/data to identify anomalous conditions and determine whether a detailed assessment (i.e., assessment initiator observed) or risk mitigation is required to demonstrate fitness-for-service.

The evaluation can address the overall riser or components thereof where damage or adverse conditions have arisen or occurred.

Findings from the evaluation shall be used as a basis for supporting or adjusting the IM strategy (see 5.4) and IM program (see 5.5), and shall conclude either that:

a) the riser is fit-for-service between inspections;

b) the riser is fit-for-service between inspections and requires on-going scheduled maintenance/monitoring/inspection (with a specified scope); or

c) remedial measures (immediate or longer term) are required to render the riser fit-for-service.

Evaluation should address risk evaluation, assessment initiators, assessment, and mitigation measures.

Evaluation does not automatically imply a detailed riser analysis and should be based on a qualitative analysis of the riser that incorporates engineering judgement, operational experience, research data, qualitative screening analysis, and/or predictive techniques to assess the effect that new information/data have on the IM strategy. Evaluation can include a review of results from a previous design or assessment analysis of the riser, without performing a detailed assessment. IM data and assessments for similar risers or components can be used in the evaluation as well.

The evaluation phase can result in no change, or it could indicate degradation or damage that requires assessment. The assessment could result in some combination of remediation, modification of operating procedures, additional monitoring, and additional or more frequent inspection. Attention should also be given to trends in inspection and monitoring data over time, as well as data from similar risers.

5.3.2 Factors to Consider

Evaluation should address all factors relevant to the integrity of the riser, including:

— riser age, condition, original design criteria;

— riser service—i.e. production, drilling, water injection, gas injection, gas lift, export;

— flow characteristics—i.e. flow rates, fluid properties, pressure, temperature, chemical injection, sand content, H2S, water cut;

— TTR annulus conditions (vent rate monitoring, gas sampling, annulus vacuum, and/or positive pressure testing);

— outer sheath integrity and annulus conditions for flexible risers;

— polymer coupon sampling for flexible risers;



— host platform motions;

— analysis results and assumptions made in the original design or subsequent assessment;

— degree of uncertainty in metocean criteria that can lead to conservative assumptions;

— metocean hindcast data in lieu of, or supplemental to, measured data;

— occurrence of any damage during transportation or installation;

— extent of inspection during fabrication, transportation, and installation;

— in-service inspection findings;

— learning from other similar risers;

— riser modifications, additions, and repairs/strengthening;

— riser condition after an accidental loading, extreme metocean event (e.g. hurricane, high current event), or excursion beyond design limits (e.g. pressure, temperature, corrosive fluids);

— fatigue sensitivity and verification of fatigue performance;

— past performance of corrosion protection system;

— riser monitoring data.

Consideration should be made for how these factors change over time. For each riser or group of similar risers, potential threats specific to those risers should be evaluated in terms of risk of failure and that the plans required to mitigate likelihood of failure or the consequences of failure. This information should be used to help establish the assessment initiators described in Section 6.

5.3.3 Risk Evaluation

5.3.3.1 General

An owner/operator can choose to adopt a risk-based strategy that optimizes inspection resources and planning. If a risk-based IM strategy is adopted, risers should be assigned to the risk category based upon the combination of likelihood of failure and consequence of failure.

IM can be done on a risk-basis, on a prescriptive basis, or on some mix of the two. However, even if a prescriptive approach to inspection and monitoring is taken, a risk assessment for the riser system should still be conducted and the IM plan constructed to manage the risks accordingly.

Risk can be presented in a variety of ways to communicate the results of the analysis to decision-makers and inspection planners. One goal of the risk determination is to communicate the results in a common format that all parties can understand. A risk matrix can be helpful in accomplishing this goal.

An example of a simple risk matrix is shown in Figure 2. In this figure, the consequence of failure and likelihood of failure categories are arranged such that the highest risk ranking is toward the upper right-hand corner. Owner/operators can decide to adopt more detailed risk assessment techniques or more complex matrices to further subdivide the characterization of the consequence and/or likelihood of failure. Most operators have more comprehensive risk assessment matrices for general hazard assessment that can be adopted for riser IM. Examples are also available in industry standards, such as DNV-RP-F206.



Risk categories are typically assigned to the boxes in the risk matrix. For the example matrix, symmetrical risk categories have been assigned. They might also be asymmetrical where for instance the exposure category can be given higher weighting than the likelihood category.

Figure 2–Risk Categorization Matrix Example

Conseq

uence o

f F

ailu

re

High Risk

Level 2 Risk

Level 1 Risk

Level 1

Medium Risk

Level 3 Risk

Level 2 Risk

Level 1

Low Risk

Level 3 Risk

Level 3 Risk

Level 2

Low Medium High

Likelihood of Failure

Risk categories can be used for setting inspection intervals and work scopes as part of a risk-based IM strategy. For example, a 3x3 risk matrix, as shown in Figure 2, can be used to categorize the risers as follows:

— Risk Level 1: Major focus of resources, which can include an increased inspection frequency and intensity of inspection and/or more detailed engineering;

— Risk Level 2: Moderate focus of resources;

— Risk Level 3: Less focus of resources, which can include a reduced inspection frequency and scope of inspection.

The example provided in Figure 2 is generic; however, the risk matrix does allow differentiation of the IM focus for various combinations of consequence and likelihood. It is up to the owner/operator to add rigor and calibration to the risk assessment process that makes sense for a riser or group of similar risers.

The results of risk assessments, including mitigations required to reach the final risk levels, should be documented.

5.3.3.2 Consequences of Failure

The consequences of failure for a riser can include life safety, environmental impact, social impact, economic loss, and damage to the reputation of the owner/operator.

Life safety should consider the maximum anticipated environmental event expected to occur while personnel are on the host platform.

The consequence of failure should include consideration of the anticipated impact to life safety, the environment, the possible economic impact through losses to the owner (riser and equipment repair or replacement, lost production, etc.), and the anticipated losses to other operators (e.g. lost production through trunk lines). Depending on the robustness of the component or system, the consequence of a specific failure may be acceptable within a period and mitigation measures employed.



5.3.3.3 Likelihood of Riser Failure

If the owner/operator chooses to adopt a risk-based riser IM strategy, the IM data should be evaluated to determine the likelihood of riser failure. The likelihood that a riser will fail because of loading is a function of the robustness of the riser.

Each riser has a likelihood of failure based on key characteristics. Damage or deterioration can indicate that the strength of a riser has reduced, potentially increasing the likelihood of failure.

5.3.4 Assessment Initiators

Evaluation should provide recommendations for performing an assessment for changes that can increase the riser’s operational risk, including for changes in: condition, action, criteria, consequence, and use.

5.3.5 Mitigation Measures

Evaluation of risk mitigation options to reduce the likelihood and/or consequence of failure should be considered at all stages of the IM process. Recommendations for evaluating risk reduction measures are provided in Section 10.

5.4 Assessment

5.4.1 Assessment Process

If the engineering evaluation determines that the riser operational risk has significantly changed, some level of engineering assessment analyses should be performed to determine whether the riser achieves the required performance level or whether risk reduction or mitigation measures are required. The assessment is part of evaluation, as illustrated in Figure 1.

Assessment should demonstrate that the performance of risers or riser components achieves the required fitness-for-service acceptance criteria, or whether risk reduction or mitigation measures are required. The assessment process may involve gathering more information in the form of monitoring, materials testing, sampling, or more detailed inspection.

Assessment is step-wise with increasing complexity and is typically accomplished by performing an analysis of the system or component. Recommended methods of assessment and analyses are provided in the assessment requirements (see Sections 7 and 8).

5.4.2 Assessment Initiation

Motives for performing a riser assessment vary and should be established prior to performing the assessment. The selection of the assessment method is influenced by the assessment motive, which can include:

a) Supporting an evaluation—For risers where the evaluation has determined that an assessment of the structural strength is required, an assessment should be performed to demonstrate that the riser achieves the performance level required by the IM strategy;

b) Categorizing the riser likelihood of failure—For risk-based IM strategies, an assessment should be performed to determine the likelihood of failure and provide input into categorizing the riser’s structural risk;

c) Supporting an inspection program—An assessment should be performed to determine the locations required for inspection and for setting inspection anomaly threshold reporting requirements;

d) Supporting a monitoring program—Risers that have included monitoring as part of their IM strategies should be assessed to provide information on the threshold that would indicate a change in the condition;



e) Supporting a mitigation strategy—For risers that have included planned mitigation as part of their IM strategies, an assessment should be performed to provide information on the riser operating limits.

5.5 Strategy

5.5.1 General

An IM strategy shall be developed that defines the in-service inspection, monitoring, and maintenance plans that should be performed over the service life of the riser. The strategy should reflect the overall philosophy for managing fitness-for-service that can vary depending upon the design margins, field life, service conditions, and fluid properties. The strategy can also take account for multiple risers of similar design and service where inspection and monitoring data can be shared. These factors can influence the philosophical approach, affecting the extent of future maintenance activities as well as varying the degree of reliance between inspections and monitoring activities to confirm fitness-for-service.

The IM strategy should identify the frequency, type of activities, and work scopes required for the riser components and provide guidance necessary to execute the associated activities. These activities should include developing strategies for inspection, maintenance, and monitoring.

IM strategies are typically generated during the design by the project team and handed over to the operating team. Project and operating teams have important roles in the initial specification and development of the IM strategies, including the identification of how the riser is expected to respond and the limitations inherent in the design, whether in the form of loading limitations or environmental restrictions that could apply to weather-sensitive operations.

The overall IM strategy philosophy should be developed during the concept or preliminary design stages. Inspection, monitoring, and maintenance plans should be developed during the later detailed design stages, ideally early enough that any potential plan implementation and execution issues can be addressed within the design.

This RP provides guidance on the development of an IM strategy that accounts for specific riser features, critical elements and the systems, and industry experience, with guidance on inspection, monitoring, and maintenance strategy development.

IM strategy should be compiled into an evergreen document that is periodically reviewed and updated, including the evolving risks in the operation.

5.5.2 Inspection and Monitoring Strategies

An inspection and monitoring plan should be developed for each riser or group of similar risers. The inspection and monitoring plan defines the frequency and scope of inspection, the tools and techniques to be used and the deployment methods. The inspection and monitoring plan should cover the anticipated remaining service life of the riser and should be periodically updated throughout the riser’s service life following receipt and evaluation of IM data, e.g. inspection data, results of riser assessments, monitoring data, etc.

Detailed recommendations for inspection and monitoring plans are provided in Section 6.

Inspection strategies can vary significantly depending on the characteristics of the operator’s riser portfolio. The inspection strategy for a riser should be integral to the overall IM strategy for that riser to ensure that fitness for service is maintained, and can depend on many factors including:

— condition of the riser;

— in-service monitoring data availability;

— critical locations access for NDE and repair;



— effectiveness of NDE methods;

— robustness of the design to defects;

— future service requirements;

— credible risks to the riser system.

The IM strategy should define the method of inspection and monitoring, data to be collected, frequency of collection, and entry into the IM data management system. For specific monitoring requirements, see Section 6.

5.5.3 Maintenance Strategies

Most risers are designed to not require routine maintenance over the life of the riser. However, some riser components can require maintenance, typically components that are easily accessible, such as TTR tensioner systems or top hang-off mechanisms at deck level. The IM strategy should address all required maintenance activities.

5.6 Program

The IM program represents the execution of the detailed work scope and shall be performed to complete the activities specified in the IM strategy. The IM program shall include the activities defined within the IM strategy over the platform service life and includes programs for inspection, monitoring, and maintenance.

To complete the IM process, data collected during the IM program should be incorporated back into the IM data management system. Consistency, accuracy, and completeness of inspection, maintenance, and monitoring records are important, since these data form an integral part of the IM process. Specific requirements for the execution of the work scope, including data recording and reporting requirements, should be defined within the inspection, monitoring, and maintenance plans.

6 Inspection and Monitoring

6.1 General

Inspection and monitoring are part of the evaluation and strategy stages in the IM process. Inspection and monitoring encompass the collection of data to determine the condition of the riser over the course of the life of the riser. Results of inspection and monitoring activities should be evaluated against the design envelope to determine if any assessment initiators have been triggered.

The IM plan should address identified threats to riser integrity and include a means for determining the present condition. The IM plan should ensure that adequate and appropriate means of inspection and monitoring are in place to allow evaluation and assessment of the riser against these credible threats. This could be achieved by continual measurement, periodic measurement, visual inspection, or other means of inspection.

Inspection and monitoring could also include indirect measurements from which inferences can be made about riser integrity. For example, regular monitoring of pressure, temperature, fluid properties, metocean data, and platform motions can provide data from which to infer aspects of the condition of a riser. The inverse can also be true. Absent such measurements, it can be difficult to substantiate the condition of a riser.



6.2 Riser Inspection

6.2.1 Risk-based Inspections (RBI)

Risk assessment should be used as a basis for developing a riser system IM program. A risk-based approach allows an owner/operator to prioritize and optimize the use of inspection and monitoring resources. The risk-based strategy for the development of an IM program should address inspection and monitoring. Scope of work should be based on an understanding of a riser system’s credible threats, susceptibility to damage, consequences of damage, and the known condition.

For an owner/operator that has adopted a risk-based IM strategy, the inspection and monitoring program should be consistent with the overall IM strategy, based on the data evaluation. The inspection scope should comprise a risk-based inspection interval, a risk-based inspection scope, the relevant deployment method (e.g. diver vs remotely operated vehicle [ROV]), and inspection technique (e.g. general visual vs close visual or NDE). The level and frequency of inspection can differ depending on the risk level of the riser (i.e. likelihood of failure and consequence of failure).

Development of inspection and monitoring intervals should account for the time-dependent threats to be able to identify and address the threat before it becomes realized. For example, the risk-based interval could require adjustment to account for the design life or present condition of the CP system or coatings.

The timing for the first in-service inspection should be determined from the completion date of the baseline inspection. The risks and inspection intervals should be reevaluated based on the inspection results.

6.2.2 Default Inspection Program

A riser inspection program should address all credible threats. The inspection program should include visual inspection of the entire riser system, above and below water. The inspection interval should be based on experience with a portfolio of similar risers (i.e. similar design and operating conditions) and OEM recommendations. If the threats to a riser are substantially different from the existing portfolio, a comparative threat assessment should be done to determine if inspection intervals should be modified to address the new threat profile.

If the owner/operator does not operate a portfolio of similar risers, the inspection intervals should be no greater than one year for above water components and riser hang-off systems, and no greater than three years for the rest of the riser system.

See API 2RD, 1st Edition and DNV-RP-F206 for guidance on establishing inspection intervals.

For retrievable components, appropriate NDE should be performed after retrieval and prior to future use.

For manufactured components, such as TTR tensioner systems, flexible joints, bend restrictors, flexible pipe, or VIV suppression devices, the manufacturer’s recommendations for inspections and associated intervals should be followed as well.

For riser systems with existing anomalies, a risk-based inspection plan should be developed.

6.2.3 Inspection Strategy

An inspection program should be established to cover all inspectable components of the riser system. The type of inspection performed needs to be effective enough to provide required information on credible integrity threats.

The following elements should be included in the inspection strategy: baseline, in-service, and event-driven.



6.2.4 Baseline Inspections

A baseline inspection should be performed to establish the as-installed riser condition following the riser installation and prior to execution of the periodic operating inspection plan. The objective of the baseline inspection is to provide a basis against which IM evaluation can be performed throughout the riser service life. The baseline inspection should identify any anomalies for future IM—e.g. damaged or missing VIV suppression, missing anodes, coating damage.

The minimum scope of work for a baseline inspection should consist of the following, unless the information is available from the installation records:

— perform visual survey of the riser system, up through the splash zone if applicable. If practical, include video or photographs of the entire riser for future reference;

— verify the condition of coatings, insulation, and CP systems;

— confirm the condition of installed appurtenances, such as VIV suppression and buoyancy;

— confirm location and condition of touchdown point for catenary risers;

— verify tension and stroke settings for TTRs are within the nominal settings. Record baseline settings.

6.2.5 In-service Inspections

6.2.5.1 General

In-service inspections can be a combination of external and in-line inspections using appropriate inspection techniques. External inspection methods, frequency, and the subsequent evaluation plan will differ above and below water.

In-service inspections should be carried out at an interval consistent with the IM strategy adopted by the owner/operator, as given in 6.2.1 and 6.2.2. Inspection intervals are determined based on either the riser risk-based evaluation or based on the default minimum inspection program.

If during the inspection program, anomalies are discovered that could potentially affect the riser integrity, qualified personnel should conduct an evaluation to determine when additional inspection and/or remedial measures should be undertaken. Additional inspections could require use of more detailed inspection techniques. Damage, anomalies, and follow-up activities should be documented, and records and reports of such retained.

6.2.5.2 Above Water Inspections

If the riser system extends above the waterline, inspection should include visual examination of the riser system from the waterline to the riser top boundary. The associated components including the supporting clamps should be inspected for presence of damage, corrosion and anomalies.

The above water inspection should include coating inspection to assess the effectiveness and condition of the various protective coating systems on the riser components. The inspection should detect deteriorating coating systems and corrosion. The inspection should describe the type of coating systems for the components inspected and record specific locations and extent of coating deterioration.

If damage, external corrosion or coating deterioration is observed, a record of the damage should be made with sufficient detail to allow engineering personnel to determine if further inspection, monitoring or repairs are required. Damage records should include measurements, photographic documentation, and drawings.



Detailed laser scans and/or external NDE can confirm remaining wall thickness where corrosion has been identified; such inspections can measure direct wall thickness or external wall loss or screening such as guided wave. Internal gauging of some TTRs might be possible.

6.2.5.3 Below Water Inspections

Below water riser inspections should be performed to detect, measure, and record any damage, deterioration, or anomalies that affect riser integrity. Deterioration could include corrosion, anode depletion, coating/insulation damage (including deformation due to overload and cracking due to fatigue cycles), mechanical damage, elastomer degradation on riser top termination units (e.g. flexible joints, stress joints), excessive wear at riser keel joints or guides, damaged or missing VIV suppression devices, and damaged or missing buoyancy. Anomalies could include non-operating or ineffective corrosion protection system, seafloor instability, hazardous or detrimental debris, or marine growth on VIV suppression devices.

6.2.5.4 In-line Inspections (ILI)

Where a system is designed for regular pigging operations, ILI should be considered as an inspection methodology to detect and characterize features that have developed during service. The ILI results should be used to verify fitness for service of the riser system. Where practical, an ILI should be incorporated into the baseline inspection plan. Further ILI inspection requirements can then be determined based on risk evaluation.

6.2.5.5 Special Inspections

Special inspections are non-periodic inspections that can be triggered by an event, such as an extreme environmental event or an accidental loading. Data collected during a special inspection should be used to evaluate the fitness for service of a riser system.

Post-event inspections are performed to evaluate the riser’s condition following an extreme environmental event with the potential for exceeding the design loads, or after an accidental loading (e.g. vessel impact, dropped objects, explosion, abrasion, floating debris, anchor drag).

6.2.6 Inspection Specification

The inspection program should establish specifications for inspection activities and procedures for quality assurance, quality control, and data validation. The inspection program should, as a minimum, include:

— roles and responsibilities for personnel involved with inspection activities;

— anomaly reporting and notification requirements;

— diver and ROV operator qualifications;

— NDE technician qualifications;

— measurement procedures;

— reporting formats and procedures;

— photography and video recording procedures.

6.2.7 Data Records

Records of inspections should be maintained by the owner/operator for the life of the riser system. The records should include the inspection performed, inspector, date and location of inspection, and all data obtained during the inspection. The records should be maintained in an archival and retrieval system.



6.3 Riser Monitoring

6.3.1 Monitoring Strategy

Riser fitness-for-service is influenced by various factors such as operational conditions, environmental conditions, and vessel motions, as well as factors related to the service conditions of the riser. Riser monitoring provides information to confirm the integrity of the riser, assists operational decisions, optimizes inspection, maintenance, and repair plans and offers the possibility to calibrate design tools.

Monitoring can include direct measurement of the riser response (e.g. riser motions, strains, hang-off angles, etc.) or measurement of parameters that can indirectly predict riser response (e.g. FPS motions, metocean data, pressure, temperature, fluid properties).

Historical records of monitored data are also useful in circumstances in which it is required to revise the service life of the riser system, such as for continued service beyond the original design life. The scope of riser monitoring systems should be identified based on a risk assessment.

Monitoring data from similar risers can also provide useful information on expected future performance.

Riser monitoring systems can be classified into two main categories:

— Condition monitoring is concerned primarily with ensuring the conformance of the static riser arrangement to the specified design requirements and functional design conditions, such as temperature, pressure, hang-off angle, top tension, corrosion rate, fluid composition, etc.

— Riser response monitoring is primarily focused on the dynamic response of the riser. These systems are often more complex than condition monitoring systems and can involve multiple instruments placed along the riser length. The objectives of these systems are typically to capture fatigue loads, extreme loads, strain and stress, clashing, etc. For flexible pipe risers, response monitoring can also include curvatures, hang-off-angle, and displacements at key locations.

Monitoring systems also require maintenance and can fail in service. The riser IM plan should include IM of monitoring systems to ensure they perform as required.

6.3.2 Riser Monitoring System Design and Specification

A wide range of devices are available for measurement of riser response. Variability in riser system arrangements and monitoring requirements are such that riser monitoring systems are typically designed to suit individual applications. Further, the accuracy and reliability of the instruments can vary depending on the parameters being measured and the complexity of set-up and riser configurations.

More information on riser monitoring system design and specification can be found in DNV-RP-F206.

6.3.3 Riser In-service Key Performance Indicators (KPIs)

Riser in-service performance criteria should be established such that if monitored parameters are outside an acceptable range, further investigation can be made, and appropriate remedial actions can be taken.

Table 1 lists typical in-service parameters associated with riser system operation that can be monitored (depending on the riser system) and associated typical performance criteria. In some cases, the KPI are given in terms of a single value, and in other cases they are defined by a range (upper and lower limit). This is not a comprehensive list, nor will it apply to every riser system. The IM program for each riser system should include a set of KPIs.


Table 1—Riser In-service Key Performance Indicators

Parameter Monitoring Method Criteria

Current speed

Wave height and period

Environment monitoring. Alternatively, hind-cast data can be utilized.

Current velocity, or wave height and period greater than levels from the design basis or most recent fitness for service assessment.

Host FPS excursions

Host FPS excursion monitoring.

Host FPS excursions more than those predicted at design stage (both extreme and long-term operating).

FPSO rotation/weathervaning Turret movement monitoring.

Vessel alignment with wind, wave, and current goes outside the envelope used in design. Identify any mechanical impediment to turret movement (i.e. turret lock).

Internal corrosion

Intrusive corrosion probes and test coupons for verification and performance indicators for corrosion inhibitor availability, if applicable.

In accordance with design basis or most recent fitness-for-service assessment.

External corrosion Guided wave or similar in splash zone.

In accordance with design basis or most recent fitness-for-service assessment.

Fluid composition Bore fluid monitoring. Concentration of H2S and CO2 and pH level that exceed the levels assumed at the design stage.

VIV Vessel, current, or direct riser response monitoring. Amplitudes and frequency of vibration more than design predictions.

Erosion Sand monitoring and intrusive erosion probe and coupons.

Sand concentration greater than levels assumed at design stage.

Erosion rate in accordance with design basis.

Temperature Temperature monitoring.

Upper Limit: Maximum design temperature.

Lower Limit 1: Minimum design temperature. a

Lower Limit 2: Wax appearance temperature. a

Lower Limit 3: Temperature and pressure combination leading to hydrate formation. Should be used in conjunction with pressure monitoring. a

Long-term Limit: Temperature histogram (temperature range and time within each range) resulting in an unacceptable service life (e.g. polymer aging in flexible pipe system).

Pressure Pressure monitoring.

Upper Limit 1: Maximum design pressure. b

Upper Limit 2: Fatigue design pressure if over a significant duration. b

Lower Limit 1: Minimum allowable pressure. This is typically governed by maximum allowable differential pressure in the system design.

Lower Limit 2: Temperature and pressure combination leading to hydrate formation. Should be used in conjunction with temperature monitoring.

Service loadsGlobal response monitoring (motions, loads, and strains monitoring, flexible joint angles).

Loads on or stresses in riser exceeding design predictions.

Upper/lower flexible joint angles exceeding design predictions.

TTR tensioner stroke range

Direct measurement routed to the control room for production risers or the driller’s console for drill risers.

High/low alarm settings.


a Whichever is the higher of Lower Limit 1, 2, or 3 dictates the in-service performance criteria.

b Whichever is the smaller of Upper Limit 1 or 2 dictates the in-service performance criteria.



In most cases, exceeding the performance criteria does not lead to immediate failure but can prompt further inspection or evaluation to confirm short and long-term integrity. Long term integrity issues such as fatigue or accelerated corrosion could require that the service life be reassessed. Other parameters can be system specific, e.g. tension in the tether system for a flexible riser. Changes during operations can require modification and update to monitoring requirements and KPIs.

Internal corrosion mitigation can be addressed through material selection (i.e. through corrosion resistant alloy [CRA]) or corrosion inhibition through chemical injection. Where corrosion inhibition (CI) is used, the limitations of the CI qualification in terms of flow conditions should be clearly documented, and the flow conditions should be monitored and checked against these limitations.

Additionally, flow conditions including composition are important data that can be utilized for managing integrity and flow assurance.

6.3.4 Reporting and Analysis of Monitored Data

Data should be maintained, saved, and archived for the full service life to support future integrity assessment and continued service beyond design service life. Access to real-time data can be beneficial for operations so that the operator can see immediately if any riser performance criteria have been exceeded or have input data readily available for analysis and assessment purposes.

Monitored data for a riser system for the specified period should be collated in a report which should include recommendations based on any excursions outside the riser performance criteria. Also, trends should be noted. For example, TTR top tension can decrease gradually over time and need periodic adjustment. Even if the measured tension does not exceed design limits, the trend can indicate excursion exceeding design limits in the future.

6.3.5 Monitoring Plan

The monitoring plan should be based on threat assessments for each riser and developed in coordination with the inspection plan. Refer to Table 1 for monitoring methods that should be considered, depending on the particular threats to the riser. At a minimum, the following monitoring should be included:

— pressure and temperature;

— fluid properties, including any injected chemicals;

— riser tensioner settings and annulus pressures for TTRs;

— host FPS motions;

— metocean conditions.

7 Riser Assessment Process

7.1 General

Riser assessment is a process by which a riser’s fitness-for-service is evaluated once the riser is installed. The assessment process is step-wise with increasing complexity and is typically accomplished by performing an analysis of the riser for the associated limit states. Assessment can consist of demonstrating that a riser survived with little or no damage an extreme loading event that is as severe as or more severe, by a margin, than specified in the design basis. Assessment methods are analytical and empirical in nature. The riser fitness-for-service assessment process should review previous failure mode studies and include new operational data to capture possible new riser failure modes.



The overall assessment process consists of the following:

— Determine if an assessment initiator exists.

— Gather the assessment information.

— Select the assessment method.

— Determine if the riser meets the performance criteria (see Section 8).

— Ensure data and changes are communicated across interfaces (see Section 9).

— Implement risk reduction measures, if necessary (see Section 10).

7.2 Assessment Initiators

7.2.1 General

An assessment initiator is defined as a change in condition that goes outside of that used in the original design basis or a previous in-service assessment. For each riser in service, a table of assessment initiators should be compiled against which any new data are tested. If the new data go outside of the safe operating envelope, or it is unclear if it has exceeded the safe operating envelope, then the assessment process should be initiated. The result of an assessment can be a repair or modification that brings the riser back within the safe operating envelope, or it can result in a modification of the safe operating envelope with a corresponding update of the data in the IM process so that future inspections and assessments will be based on the most recent data.

Table 2 is a list of typical initiators for various types of risers. For a riser, there could be other design conditions that require additional initiators that should be identified, and others could not apply. The operator will also need to compile the relevant design data that corresponds to each trigger for a riser. The IM evaluation process should make clear how inspection and monitoring data are evaluated against specific initiators to determine whether assessment is required.

The table of initiators and safe operating envelope criteria for each riser should be reviewed periodically and updated if needed.

Degradation mechanisms and failure mechanisms applicable to flexible riser systems and associated causes are tabulated in API 17B and are not specifically addressed here other than in Table 2.

7.2.2 Life Extension

Life extension is an assessment initiator that is triggered by the increase in projected end of service life beyond the original design. The same assessment process is used as for any other riser fitness-for-service assessment except for the revised service life. The results of the assessment can be that the riser is fit-for-service in its present condition for the longer service life, or that some combination of repairs, component replacement, additional inspection, or additional monitoring are required to extend the service life.

7.3 Assessment Data

7.3.1 General

Assessment data are the information necessary to complete the assessment. Up-to-date information regarding the riser system is required for the IM process. Information on the original design, fabrication, and installation, as well as in-service monitoring, inspections, engineering evaluations, structural assessments, modifications, and operational incidents, all constitute parts of the IM knowledge base.

Riser IM data fall into three broad categories: (1) characteristic data, (2) condition data, and (3) operating data.



Table 2—Riser Assessment Initiators and Triggers

Initiator Category

Riser Type Initiators/Triggers Potential Causes Failure Modes/Degradation

Mechanisms to be Checked

Change in design basis

All

Metocean criteria change

Change in magnitude and direction of waves, ocean currents, and wind Strength, fatigue

Increase in SCF or SAF

Deviation from pipe, weld grinding, joint and connector specification

Local mechanical damage

FatigueWelding fatigue detail

Welds did not meet fatigue requirements in accordance with the design S-N curve

Fatigue damage during installation beyond the design allowance

Additional reeling cycles

Longer exposure to severe weather

Platform motions

Host FPS modifications leading to changes in loading or response—e.g.:

— increased wind load;

— change in platform draft;

— change in platform VCG envelope;

— change in mooring characteristics,

— change in riser loading on platform (i.e. other risers added, removed, modified, changes in service)

Strength, fatigue

Riser configuration change

Design installation tolerances exceeded, e.g. touch-down point, departure angles, space-out, riser top-tension

Change in soil condition

Change in soil condition due to change in host FPS planned location before installation or additional measurements in same site.

New requirementsChanges to design standards

Learnings from incidentsWill depend upon nature of change

TTR

Riser base installation

The wellhead conductor or suction pile installation exceeds the angular and locational tolerance limits

Strength, fatigue, wear (for drilling TTRs)

TTR surface equipment change

Change in surface tree or BOP configuration causing change in dimensions and weight

Strength, fatigue

Change in TTR annulus fluid

Operational decision Strength, fatigue, corrosionAddition of gas lift tubing



Operational events

All

VIV suppression device Missing or damaged strakes/fairings

Strength, fatigueMarine growth

Marine growth degrading the effectiveness of VIV suppression and increasing drag forces

Riser coatingDamage to riser coating leading to corrosion or hydrate formation (e.g. during installation, ROV operations, riser interference)

Cathodic protection system Complete depletion of anodes Burst, fatigue

ClashingCollision between adjoining risers (either observed or based on local damage at matching locations)

Strength, collapse, wear

Pressure & temperature

Change in reservoir conditions

Change in operational procedures (e.g. choking on production risers, line packing or operating pressure changes for export risers)

New wells or side-tracks with higher pressure or temperature

Hydrate remediation operations

Topside boarding valve accidentally shuts down

Burst, strength, fatigue

Product fluid composition

Change in H2S and CO2 concentration, crude oil pH value change Corrosion, fatigue

Slugging Change in production phase propertiesStrength, fatigue

Seabed condition Trenching at touchdown zone of SCR

Pressure drop Connection leakage Sealability

Service change

From water injection to production (or vice versa)

Unanticipated increase in water-cut or gas fraction

Burst, collapse, strength, fatigue, corrosion, hydrate formation

Flow assurance Hydrate, wax, etc. Strength, fatigue

Operation outside specified limits

Several possible causes, such as going beyond the operating limits on depressurization rates and minimum external exposure temperature at exposed topside end fittings

Depends on situation

SCR, flexible

Riser hang off system change

Replacement of a flexible joint, stress joint, or bend stiffener Strength, fatigue

TTR/SCR Pipe wall loss

Metal loss in pipe wall due to corrosion

Wall loss due to drill pipe tool joint key seating

External corrosion

Burst, collapse, strength, fatigue

Table 2—Riser Assessment Initiators and Triggers (Continued)

Initiator Category





Unplanned or unintended events

All

Extreme storm

Storms with return periods exceeding the design storm (i.e. 100-year event)

Lesser storms if a riser component is particularly susceptible to low cycle fatigue Strength, fatigue

Extreme current Sustained currents with higher magnitude, profile or duration than in the design basis

Large offset of host FPS More than one mooring line damaged Strength

Excessive VIM of host FPS

VIM of host FPS exceeds design amplitudes and/or durations Fatigue

New metocean phenomena

Soliton or topographical Rossby waves (TRW) observed Strength

Accidental damageTopside dropped objects falling on riser, boat collision, fishing activities, ROV operations, anchor drag

Collapse

Buoyancy modules damage or movement

Due to clashing between risers

Mechanical failure of attachmentStrength, fatigue

Coating damage Fishing activities, ROV operations, clashing, anchor drag, boat collision Corrosion

Flexible/umbilical

Damage or defect or unforeseen degradation or failure in any layer of flexible riser pipe and its end fittings

Possible causes are tabulated in API 17B for static and dynamic applications of flexible pipes

Associated consequences (failure mechanisms) are listed in API 17BDamage or defect or

unforeseen degradation or failure in a component of a flexible riser system

Possible causes are tabulated in API 17B

Damaging to outer sheathing/armoring of the umbilical

Clashing, dropped objects, etc. Strength, fatigue including local effects

Damage to bend stiffener

Dropped objects, over bending, etc.Strength, fatigue including local effects. Associated consequences (failure mechanisms) are listed in API 17L2.

Damage to bend restrictor

Damage to tether Increased motions, dropped objects, trawling, etc.

FlexibleExcessive pressurization or depressurization rates

Change in service

Process upset

Associated consequences (failure mechanisms) are listed in API 17B

SCR, flexible/ Turret-lock Mechanical failure in turret bearings Strength, fatigue

Life extension All Additional service life Planned operation beyond original design life

Burst, collapse, strength, wear, fatigue, sealability, corrosion

Table 2—Riser Assessment Initiators and Triggers (Continued)

Initiator Category





7.3.2 Characteristic Data

The riser system characteristic data are the baseline data that represent the riser at installation. The characteristic data should include design data as well as fabrication and installation data, including:

a) design documentation, including:

1) design premises;

2) codes and standards;

3) metocean and geotechnical data and reports;

4) design and analysis data and reports;

5) riser specifications;

6) riser fabrication and construction drawings.

b) third-party verification reports;

c) risk and mitigation related documentation including:

1) integrity management strategy plans;

2) HAZOP and HAZID registers;

3) specifications for protective systems;

4) emergency response plans.

d) as-built riser information, including:

1) drawings;

2) material traceability reports (MTR);

3) welding Procedure specifications (WPS) and supporting procedure qualification reports (PQR);

4) nondestructive examination (NDE) records;

5) inspection and test plans (ITP);

6) non-conformance reports (NCR).

e) installation and commissioning records, including:

1) post-deployment testing;

2) pre-commissioning records;

3) commissioning records;



4) as-built installation survey data (e.g. final space-out, wellhead position and angle, departure angles, touch-down point).

f) records and documents relating to the management of change system;

g) baseline inspection data;

h) operation and maintenance manuals.

7.3.3 Condition Data

The riser system should be assessed based on its present condition, accounting for any damage, repair, scour, or other factors that could potentially affect its fitness-for-service. The owner/operator should ensure that any assumptions made are reasonable and that the data are accurate and representative of actual conditions at the time of the assessment, or for future modifications to the riser system.

The condition data represent the changes to the characteristic data or variations within the characteristic data that can occur during the life of the riser system. The condition data could include the following:

— in-service data—external inspection reports/videos, ILI data/reports, corrosion protection system;

— damage evaluation data and statements of riser fitness;

— strengthening, modification, and repair (SMR) data;

— riser system and platform modifications;

— operational incident data, including riser IM incident records/reports;

— integrity assessment reports;

— lessons learned.

7.3.4 Operating Data

Operating information should include forms of monitoring that are relevant to riser IM, including:

— pressure, temperature, production chemistry, and other fluid data;

— tension measurement;

— annulus pressure;

— tensioner pressure and stroke (if available);

— riser motion;

— platform motion;

— metocean data;

— other monitoring data in accordance with the monitoring plan.



7.4 Assessment Process

7.4.1 General

This RP describes three approaches to performing riser fitness-for-service assessments. The choice of approach will depend on the nature of the assessment initiators. Recommendations for the implementation of the assessment methods is given in Section 8, based on common degradation mechanisms and failure modes of steel riser pipes and connectors. These methods can also be applicable to other metals such as aluminum and titanium if the original design for these components met widely used industry design standards.

7.4.2 Simplified Assessment

It is recommended to start with a simplified assessment method based on reviewing existing design reports, fabrication records, and installation reports. Not all initiators warrant a full reanalysis of a riser system. In many instances, simplified methods of assessment can be used in place of more complex and time-consuming analysis. Simplified methods can serve as screening to determine the extent of detailed analysis required, if any, to demonstrate fitness for service. Such methods are typically used when a previous detailed analysis of the riser system is available, or when it is like another riser system that has been analyzed in detail.

7.4.3 Full Assessment

A full assessment approach reestablishes the baseline of the fitness for service. This could include global or component finite element analysis or general hand calculations. Section 8 outlines the full assessment method in more detail.

7.4.4 Riser In-service Verification Testing

Riser in-service verification testing can include leak testing and pressure testing. Such testing should be performed in accordance with corresponding riser code requirements and controlled through pre-approved procedures.

8 Assessment Methods

8.1 General

This section provides recommendations for assessment methods that should be applied to various failure modes for risers. These are not the only methods that can be used, or the only failure modes that could be important for a riser.

The first step in the riser assessment should be to determine which failure modes and degradation mechanisms are affected by the assessment trigger. Once this is determined, appropriate assessment methods as listed in the following sections can be applied. Alternative methods can be applied with engineering judgment.

8.2 Sensitivities

When conducting riser assessment, in the absence of as-built data or with the availability of new data, uncertainties associated with the manufacture and installation of the riser system should be identified and addressed, including:

a) as-built dimensions and properties, including:

1) subsea wellhead angular misalignment of the wellhead, with respect to vertical;

2) subsea wellhead horizontal placement with respect to the nominal seafloor location;

3) actual riser tension;



4) tensioner stiffness;

5) flexible joint or flexible bending stiffness.

b) tensioner stroke range;

c) mill tolerances (pipe weight, wall thickness);

d) soil stiffness;

e) range of anticipated platform payload and riser configurations;

f) range of anticipated mooring system positioning (i.e. to access wells).

8.3 Functionality

8.3.1 General

All riser components and appurtenances should remain in such a condition that they perform their intended function. Any damage or degradation that impedes the ability of a component to perform its intended function should be an assessment trigger, and actions should be taken to either confirm fitness-for-service in the present condition, or to specify remediation actions to restore the riser as fit for service.

Riser assessment should take into account the effects of the reduced functionality of a damaged or missing component and include the entire time period during which the reduced functionality was in effect.

EXAMPLE During a periodic inspection, it is discovered that several buoyancy modules are missing from a pipeline riser. During the last inspection one year before, the modules were in place. The purpose of the buoyancy in the design was to mitigate the motions of the riser near the touch-down point, so it is anticipated that removing buoyancy could adversely affect fatigue at the touch-down point. In the reassessment, the riser is modeled with and without the buoyancy. The without-buoyancy model is used to confirm whether any strength design limits were exceeded based on metocean data observed in that year, and for computing the fatigue damage for the time it was missing. The fatigue damage for all of the time prior to the last inspection is based on all buoyancy in place.

Common riser components that should be periodically verified for functionality include: VIV suppression, buoyancy, coatings and insulation, and cathodic protection (CP) system.

8.3.1.1 VIV Suppression

VIV suppression typically consists of helical strakes that are formed in plastic or metallic modules secured to the riser by straps. In some cases, fairings are used, which are free to swivel about the riser, supported by a collar clamped to the riser. VIV suppression devices should be maintained in a condition so that they function as designed.

Visual inspections should be used to confirm that the VIV suppression remains in place and is not structurally damaged.

For helical strakes to function properly, the area between strakes should be relatively free of marine growth or debris. The depth of the strakes is generally designed such that it can still function with some marine growth, but this varies and should be clearly documented in the design. If the marine growth exceeds this minimum level, it should be removed.

For fairings to function properly, they should be able to freely rotate to align with the direction of the current. If damage, debris or marine growth hinders the rotation of a fairing, it will not suppress VIV and will increase the drag forces on the riser at some headings. Marine growth on the fairing itself can also reduce the effectiveness of a fairing even if it is free to rotate and should be cleaned. Limits on fairing effectiveness should be documented in the design.



If the effectiveness of VIV suppression is reduced for a significant period, the effect on riser VIV fatigue should be taken into consideration in future assessments.

8.3.1.2 Buoyancy

If buoyancy is used to support the riser in some way (e.g. to relieve the top tension or to adjust the shape) and inspection shows it to be damaged or missing, reassessment should consider the effect on the riser strength and fatigue.

Buoyancy can also lose some of its effectiveness over time due to other mechanisms not necessarily detectable by visual inspection, including leaks in steel modules, compression, or water absorption of syntactic foam. Reduction in effective buoyancy for whatever reason can also be detected by measuring the shape of the riser to see if it has changed over time. If the top tension is measured, this can also be an indicator. Changes in riser shape and loading due to buoyancy degradation of any kind should be taken into consideration in a reassessment of the riser.

8.3.1.3 Coatings and Insulation

Corrosion protection coatings are addressed in 8.8. Other coatings can be used for abrasion resistance or as a sealer for insulation. To properly function, the coatings should remain intact. While failures in coatings that do not affect corrosion or erosion do not necessarily indicate a structural integrity issue, they are often vital to the service of the riser (e.g. flow assurance) and should be treated appropriately in the assessment process.

8.3.1.4 Cathodic Protection System

In addition to corrosion protection coatings, some risers can have a passive cathodic protection system consisting of anodes or other anodic coating, such as thermal sprayed aluminum. Cathodic protection that is missing, damaged, or somehow rendered less effective than planned should be addressed in the corrosion assessment of the riser.

8.3.2 TTR Components

Load-carrying components of the TTR system can include: tensioners/rollers, external and internal tieback connectors, and/or adjustable surface hangers.

Tensioning systems are designed with prescribed up-stroke and down-stroke to accommodate vessel motions relative to the riser. Functionality of the tensioner system can be compromised in several ways. One is debris and/or damage to the exposed cylinder rod. The cylinder rod retracts back in the cylinder and can damage the internal seals, which could cause premature wear and ultimately seal failure.

Hydro-pneumatic tensioning systems are typically designed to operate with one cylinder out of service. This should be a temporary condition, and a replacement cylinder should be installed to resume normal configuration. Operating with one cylinder out could adversely influence the rollers, as the lateral load will increase due to the non-uniform loading.

External tieback connectors are typically hydraulically operated via a ROV, while internal tieback connectors are weight set and/or rotated from the surface. Their connectors establish a mechanical attachment to an interface at or near the mud-line. A metal-to-metal seal is also established at these interfaces. Confirmation that these components remain locked after an assessment initiator is important to ensure that static and/or fatigue capacities are not compromised. This can be accomplished by visually confirming position indicators for external tieback connectors and monitoring annulus pressure for internal tieback connectors. Upon retrieval of these connectors, verification of all locking and unlocking functions should be performed by the OEM prior to redeployment.



8.3.3 SCR Components

8.3.3.1 General

The top termination of an SCR is typically either a stress joint or a flexible joint. It is in the primary load path and integral to pressure containment of the riser system. It serves the purpose of transferring the loads from the riser to the host FPS structure. Cantilevered pull tubes have also been used.

8.3.3.2 Flexible Joints

A flexible joint is designed to transfer the riser tension to the supporting structure, while minimizing the moment transferred by allowing rotation. Flexible joints include metallic and nonmetallic components. Metallic components should be assessed like stress joints. The nonmetallic components are prone to a variety of failure mechanisms. The integrity of flexible joints can be sensitive to pressure, temperature, and fluid properties. Any changes in these properties should initiate a reassessment. The design of flexible joints is typically proprietary to the vendor. The IM program for flexible joints should be developed in close consultation with the vendor to ensure that the failure modes are understood and appropriately addressed in terms of inspection and monitoring.

ROV-based inspection of flexible joints can be carried out periodically to check for visual evidence of elastomer damage or degradation. Because creep and degradation of the nonmetallic materials are signs of overall degradation and eventual failure, keeping close track of visual inspections over time and review of inspection results by the vendor is a critical element of IM for flexible joints.

8.3.3.3 Stress Joints

Stress joints have no moving parts, so functionality is the same as the riser pipe, except that it sees much higher bending moments and transfers those moments to the host platform structure. Stress joints are typically forged from carbon steel or other metals, such as titanium. The assessment methods for riser pipe apply to a metallic stress joint as well. Because of the complex geometry and the criticality of local stress concentrations, full solid FEA modeling should be used to accurately assess most aspects of stress joint integrity.

8.3.3.4 Cantilevered Pull Tubes

Some SCRs are terminated through a pull tube that cantilevers from the host FPS such a distance that the pull tube serves the function of a stress joint. If there is no mechanical connection of the riser to the pull tube at the mouth of the pull tube, then abrasion can occur over time and should be addressed in the design and in the assessment initiators.

8.3.4 Flexible Risers

For recommendations for assessment of flexible risers and associated components, see API 17B and API 17L2.

8.3.5 Hybrid Risers

Hybrid risers generally consist of combinations of components found in TTRs, SCRs, and flexible risers and should be treated similarly in terms of assessment. Unique components and failure modes should also be identified and incorporated into IM planning.

8.4 Burst

Metal loss with various depths and irregular shapes can occur in risers due to erosion, corrosion, or abrasion (wear). If the metal loss is less than the corrosion/erosion allowance specified in the design, and adequate thickness is available for the future degradation without exceeding the burst limit, no further action is required other than to record the data. If the metal loss is more than the specified design allowance value, the pipe burst pressure should be assessed using the



appropriate industry standards. API 579-1/ASME FFS-1 presents three levels of assessment for metal loss due to corrosion that can be used in the assessment. Other methods are available for consideration as well.

ILI can be performed to obtain the dimensions of corroded risers to be used as input to determine the remaining burst capacity of the riser. See Annex A for an example of a burst capacity assessment for a corroded riser.

8.5 Collapse

For risers in service, due to erosion and corrosion, metal loss with various depths and irregular shapes can occur. Damage in the form of dents can occur due to dropped objects, clashing, anchor drag on sections on the sea floor, or other causes. Metal loss and damaged condition should be accounted for in the assessment of fitness for service for collapse.

ILI can be performed to obtain the dimensions of corroded and damaged risers, including wall thickness measurements and sizes and shapes of dents.

When uniform corrosion, wear and/or erosion allowance is allowed for in design, the wall thickness used for the pipe collapse capacity assessment should be the nominal thickness reduced for corrosion, wear and/or erosion as appropriate. If the metal loss is less than the initially specified corrosion/erosion allowance, and adequate thickness is available for the future corrosion allowance, no further action is required other than to record the data; otherwise, an assessment should be done. If the metal loss is more than the specified design allowance value, the pipe’s capacity to resist the net external pressure should be assessed to the appropriate industry standard.

For most metal loss evaluations, it is recommended to first assess the characteristics of the metal loss profiles to distinguish between uniform and local metal loss. Assessment methods provided in API 579-1/ASME FFS-1 can be suitable for Level 1 and Level 2 analyses, with care taken to ensure that the factors of safety used in the fitness for service assessments are consistent with the appropriate industry standard. Assessment of collapse capacity with significant local metal loss can require finite element analysis (FEA).

Test data and FEA on the collapse of dented metallic tubes of small diameter (with D/t values between 19 and 43) have shown that the collapse capacity of a dented pipe is mainly a function of the maximum ovality of its most deformed cross section, which in turn is mainly a function of the depth of dent, and not the complex three dimensional geometry of the dent (see Mechanics of Offshore Pipelines: Volume 1 Buckling and Collapse [1] ). Ovality of a dented pipe cross section is defined as:

ΔodDmax Dmin–Dmax Dmin+-----------------------------= (1)

where Dmax is the maximum distance across the deformed cross section and Dmin is the minimum distance across the convex part of the deformed cross section, as shown in Figure 3.

For an initial assessment, the collapse capacity of dented pipe can be assessed by means of FEA of the riser pipe, including the maximum ovality at the dent, without necessarily including the detailed shape of the concave part of the dent. The detailed shape need not be included in a first assessment as long as the Δod value is correctly modeled. The detailed shape could be included in a more detailed FEA if further refinement is required. Nonlinear stress strain properties of the riser pipe material should be included in the analysis model.

Dents can result in significant reduction in collapse capacity. For example, Δod value of about 0.1 can result in 50 % reduction in the collapse capacity (see Mechanics of Offshore Pipelines: Volume 1 Buckling and Collapse [1]). The initial assessment approach described above is limited to evaluating a single dent. Dents can reduce the burst, combined loading and fatigue capacities of the riser pipe as well. Whether a dent includes a weld and/or gouge or not can affect the dent-related reductions in burst capacity and fatigue life.


Figure 3—Primary Geometric Parameters of Most Deformed Cross Section of a Dent

Dmax

Dmin


Riser pipe sections are almost always in combined loading conditions, since axial forces are always present in risers in combination with external pressure. Tension and bending have negative effects on collapse capacity.

Assessments of dents require geometric characteristics of the dent such that local FEA can be employed. The assessment should consider impact to collapse, burst, combined loading and fatigue capacities of the pipe. Nonlinear stress/strain properties should be considered in the analysis as well. The FEA model should also consider effects of neighboring transitions or unique geometric features.

8.6 Strength

8.6.1 General

The strength assessment of a riser for the combined loading effects of pressure, effective tension, and bending moment can be influenced by several factors. Analysis results from the design phase can be helpful in determining the critical load cases, which may vary depending on the portion of the riser being assessed. To verify the integrity of a riser, the most critical normal operating, extreme, and survival conditions should be selected.

Strength assessment relies on global analysis of the riser, which in turn depends on modeling of various factors associated with the riser, host platform, and foundations. Recommendations on how to address some of these factors are included in Annex B.

8.6.2 Wall Loss Due to Corrosion, Erosion, and Wear

Strength analysis to confirm the integrity of the riser or riser component can be necessary if wall loss exceeds the design allowance as detected through inspection. The as-built and as-inspected condition of the riser should be incorporated into the analysis, considering the rate of wall loss based on inspection data and time of inspections.

In the instance of metal loss due to corrosion, erosion, or wear, if metal loss exceeds the design allowance, a strength assessment should be made to determine if the riser is fit for service.

If the riser is deemed to have undergone uniform wall loss in a section such that the global behavior of the riser might have been altered, the use of global riser analysis utilizing beam elements could suffice.

If the wall loss is local in nature, such as scattered pitting, the use of component level FEA modeling can be necessary to capture the wall thickness terrain in the critical section of the riser. It should be determined whether the loads obtained through global analysis performed during the design phase are acceptable as inputs to the component



level FEA model or whether updated global riser analysis is required to capture the as-is condition of the riser. This level of assessment can also apply to dented pipes.

8.6.3 Buckling

Riser buckling assessments could be necessary due to:

— increased riser motions at the touchdown area (for SCRs and SLWRs);

— increased topsides equipment weight on TTRs;

— reduction in wall thickness due to corrosion in the free span;

— removal of lateral supports, thereby increasing the free-span of the riser.

Buckling analysis should be performed in accordance with the criteria prescribed by industry-accepted codes, such as API 2RD.

8.6.4 Riser Clashing

Riser clashing assessment should be undertaken if there is visual evidence of clashing during an ROV inspection. There are also other changes that can affect the dynamics of adjacent risers enough to cause clashing, particularly if in the original design or in past assessments the adjacent risers came close to clashing. Examples of changes that can increase the risk of clashing include:

— change in internal fluid content characteristics such as density in the riser;

— accidental removal of VIV suppression devices from the riser;

— excessive marine growth, increasing drag forces and potentially decreasing VIV suppression efficiency;

— increase in ocean currents;

— installation of a neighboring riser previously unaccounted for during the original design phase.

Clashing assessment through FEA is required to demonstrate the integrity of the riser pair. If clashing is predicted or detected, the impact forces should be calculated following DNV-RP-F203 or evaluated based on test results.

8.7 Fatigue

8.7.1 General

There are several factors that could change the predicted fatigue damage for a riser component from the original design, and hence should trigger reassessment. These include changes in loads, host FPS motions, service conditions, corrosion, wear, overload, etc.

Fatigue assessment relies on global analysis of the riser, which in turn depends on modeling of various factors associated with the riser, host platform, and foundations. Recommendations on how to address some of these factors are included in Annex B.

8.7.2 Fatigue Loads

Riser fatigue assessments should be performed for the anticipated fatigue loads within the service life of the system. Riser fatigue damage is primarily caused by cyclic loads due to first-order wave effects (direct wave loads and associated



host FPS motions), second-order host FPS motions, vortex-induced vibrations (VIV) and vortex-induced motion (VIM) of the platform. Thermal and pressure induced stress cycles can also cause fatigue, especially in certain riser components such as riser top and bottom termination units. Any significant change in these loads from the original design, including magnitude and duration, could change the anticipated fatigue life, and hence is a trigger for reassessment.

The fatigue reassessment should account for the past configuration and loading history of the riser, as well as the expected future configuration and loading of the riser.

The use of monitoring can help to give a more accurate assessment of response by permitting the calibration of the riser response model.

8.7.3 Fatigue Damage Safety Factor

The safety factor on fatigue damage used during the design phase is based on a combination of uncertainty around loading, material properties (base metal and weld), dimensional tolerances, quality control, and degradation due to corrosion and wear. Once a riser has been fabricated, inspected, installed, and has been in service for some time, the uncertainty could be demonstrated to have changed. The result could be a commensurate reduction in safety factor, or potentially, an increase in safety factor. Any change in safety factor should be firmly grounded in measured data and well calibrated analysis inferred from measured data.

The degree to which the safety factor can be modified will depend on the reliability of the measured data and any analytical processing required. Types of load measurements that could be used include, in order of increasing uncertainty and increasing reliance on inference:

— direct measurements on the riser or a similar riser;

— inferred from measured platform motions by means of well calibrated riser analysis tools;

— inferred from platform motions calculated by a well calibrated motion analysis tool based on measured metocean conditions;

— inferred from platform motions calculated by a well calibrated motion analysis tool based on hindcast metocean conditions inferred from metocean data measured at other locations.

8.7.4 Service Condition

Riser fatigue reassessment should account for the service condition to which the riser is exposed.

If the service has changed or is anticipated to change going forward (e.g. increased H2S due to reservoir souring or new reservoir zones coming on stream), then this should be taken into consideration as well. Service changes can also include chemical treatment.

EXAMPLE If the original design was contingent on continuous injection of corrosion inhibitor and corrosion inhibitor was not injected for some period of time, the potential effect on corrosion predictions should be included in the assessment.

8.7.5 S-N Fatigue Method

S-N based fatigue assessment can be performed based on the methodology prescribed in established codes of practice used by the offshore industry such as DNV-RP-C203, ASME BPVC Section VIII Division 2, ASME BPVC

Section VIII Division 3, and BS 7608.

The material fatigue properties and/or data used to determine the appropriate S-N curve should be representative of the operating conditions and should be based on the same class of materials and environmental conditions (i.e. air, salt water immersion, salt air/salt water spray, high humidity, H2S, caustic agents, cathodic protection) as expected in



service. If in-service conditions are different from what was assumed during design, the appropriate S-N curves should be used based on the actual service condition.

8.7.6 Fracture Mechanics

8.7.6.1 General

Fracture mechanics (FM) methods can be used to assess the significance of potential fatigue crack growth and/or fracture in terms of fracture instability or ductile tearing for some situations challenging the original design basis, such as the following:

— detection of any planar flaws;

— higher design loadings (resulting in higher one-time stresses and/or larger fatigue demand than originally designed);

— as part of assessing the significance of local thin areas (LTAs) (e.g., corrosion, erosion, wear exceeding design allowance) near weld in fatigue-sensitive areas;

— as part of assessing the significance of anything else that could result in higher one-time stresses and/or larger fatigue demand than originally designed.

FM assessments should be performed based on the methodology prescribed in applicable industry standards, such as ASME BPVC Section VIII Division 3, Article KD-4, 2017, and, API 579-1/ASME FFS-1, Part 9 and Annex F, June 2007, and BS 7910, and DNV-OS-F101.

FM assessment requires information from multiple disciplines over the entire service life, including fabrication, transportation, and installation. This includes data such as material properties, static and dynamic loadings, fatigue crack growth data, and service conditions.

Standard FM assessment methodologies include several steps. Care should be given when selecting steps from different industry standards for an FM assessment.

8.7.6.2 Flaw Sizing

FM assessments should be based on the worst-case flaw size, as described herein. When the significance of a detected flaw is being assessed, care should be given to appropriate sizing of that flaw, such that the potential for sizing error is addressed. Sizing error depends on several factors, such as the component material, component geometry, NDE equipment, settings, procedures and personnel, and the environment in which the NDE work was performed. When the FM assessment addresses the significance of potential flaws (e.g. the FM assessment addresses flaws that could have been originally too small to be recorded) appropriate sizing should be based on NDE done during fabrication and the potential for flaw growth during subsequent fabrication, transportation, installation, and prior service.

8.7.6.3 Design Safety Factor on Fatigue Life

The design safety factor used for fatigue crack growth assessments should be less than and consistent with the applicable S-N fatigue design, since FM assessments assume that the worst-case flaw is present. For example, if a factor of 10 is used for S-N fatigue life calculations, a factor of 5 is recommended for fatigue crack growth calculations. Recommendations for design factors are available in ASME BPVC Section VIII Division 3 and DNV-OS-F101. Alternative fatigue life design margins can be applied on a case-by-case basis with appropriate technical justifications in accordance with recognized industry standards and/or validated publication.



8.7.6.4 Flaw Growth by Fatigue

Fatigue crack growth should be based on the potential after NDE was completed, including fabrication, transportation, installation, and prior service. Worst-case fatigue crack growth should address scatter in fatigue data (e.g. mean plus 2 standard deviations), tensile residual stresses, environment (e.g. corrosively and temperature) and loading frequency. Guidance for fatigue crack growth are provided in API 579-1/ASME FFS-1 and BS 7910.

8.7.6.5 Flaw Growth by Ductile Tearing

Ductile tearing should be addressed when loads larger than specified minimum yield strength (SMYS) have occurred since NDE, including fabrication, transportation, installation, and prior service. Guidance for assessing ductile tearing is provided in API 579-1/ASME FFS-1, BS 7910, and DNV-OS-F101. Specific assessments should be conducted when assessing ductile tearing by biaxial loading, e.g. simultaneous high pressure and high axial loading on pipe.

8.8 Corrosion

8.8.1 General

Possible changes in internal and external corrosion threats during the operational lifetime should be identified and assessed (see for example DNV-OS-F201, DNV-OS-F101). The effect of changes in operating parameters on future corrosion rates should be assessed using corrosion prediction models that consider the effect of the critical parameters expected to affect specific corrosion threats. See NACE Technical Committee Report 21413 for more information on the accuracy of corrosion prediction models.

Recommendations on the grading of coating systems is provided in NACE SP0108.

8.8.2 Internal Corrosion

Wall thickness should be updated based on measured values combined with the expected corrosion in the remaining lifetime. The corrosion rates can be determined based on the observed metal loss and corrosion monitoring data (if available).

The main internal corrosion threats are usually related to the presence of water, corrosive gases (e.g. CO2, H2S), bacteria, and/or solid particles in the produced fluids. Depending on the prevalent corrosion mechanisms, an economic-effective strategy to control corrosion during the life cycle should have been implemented from the design stage. These methods can include removal of corrosive agents, cladding with a corrosion resistant alloy, corrosion allowance, and chemical treatment. The effectiveness of the method(s) selected to control internal corrosion should be assessed. For example, if chemical treatment is used to control corrosion, the reliability of the injection process should be documented and its effectiveness measured using corrosion probes and periodic wall thickness measurement.

If H2S concentration in the produced fluid is expected to increase above the values using during the design stage, an assessment should be made to assure that all materials in contact with the fluids follow NACE MR0175/ISO 15156-1. Supplementary requirements for H2S service are given in DNV-OS-F101.

For a TTR, evidence of corrosion on the ID of the outer riser joints gives rise to the assumption that for the years prior to refurbishment, the B-annulus was exposed to a corrosive fluid. Riser refurbishment activities can include honing the ID of the specialty joints and grinding the ID of the riser joint welds. Another possibility is to use new riser joints in place of refurbished joints that have consumed a portion of their fatigue lives. Thus, fatigue damage and remaining



life can be evaluated for three scenarios (below), which include different possibilities of the corrosive nature of the B-annulus in the future.

— Use refurbished riser joints and refurbished specialty joints (with honed ID) and assume the fluid in the B-annulus of the refurbished riser is corrosive.

— Use new riser joints and refurbished specialty joints (with honed ID) and assume the fluid in the B-annulus of the refurbished riser is corrosive.

— Use new riser joints and refurbished specialty joints (with honed ID) and assume the fluid in the B-annulus of the refurbished riser is non-corrosive.

8.8.3 External Corrosion

An external inspection program can be used to assess the condition of the protection against external corrosion, including:

— damage to coating;

— damage to cathodic protection anodes or attachment welds, anode depletion;

— presence of major debris that can cause damage to the external protection system;

— presence and extent of corrosion damage.

If loss or damage to coatings, anodes, or their connectors is observed, repair should be performed and inspected in accordance with established procedures. Potential measurements should be carried out to confirm adequate corrosion protection. The possible consequences of loss of corrosion protection on the long-term performance should be assessed and documented.

In the splash zone and atmospheric zone, damaged or disbonded coatings can cause severe metal loss due to corrosion, mainly in risers carrying hot fluids. Visual examination of the coating can detect damage to the coating (e.g. rust discoloration, bulging, cracking of coating) but in some cases detecting under-coating corrosion can require special consideration.

8.9 Wear

The effects of wear due to repeated contact between two or more surfaces in a riser should be identified and accounted for at the design stage. For example, riser wear can be caused by:

— repeated abrasion between the riser and seafloor at the touchdown area of a catenary riser;

— repeated contact between the riser and bellmouth at the pull tube bellmouth of a catenary riser during riser pull-in through the bellmouth, or in service;

— internal contact between the drill pipe or drill pipe tool joint and the riser casing in the high curvature areas of a top-tensioned riser during drilling operations;

— clashing between risers and surrounding structures caused by higher than anticipated platform motions and/or metocean environment;

— relative moving parts such as shackles or ball joints.

Appropriate wear allowances are typically included during the design stage of the riser. Periodic inspections in accordance with established procedures should be carried out to identify and assess high wear areas in the riser. The



possible consequences of the wall loss caused by wear or the susceptibility to corrosion due to damage to riser coating caused by wear should be assessed and repaired as needed.

Wear rates included in the design should be verified during the periodic inspections. In the case of riser wear due to drilling operations, wear rates should be verified via laboratory experiments in accordance with API 7CW and FEA simulations that model side loads between the drill pipe and riser under appropriate weather conditions for drilling. The effect of the change in operating parameters on the wear rates, such as increase in drill pipe rotation speeds or durations, use of different drill pipe hardfacing material, or change in the characteristics of drilling fluid should be assessed through laboratory experiments or past relevant experimental data.

8.10 Sealability

8.10.1 General

Many types of risers, particularly retrievable risers with mechanical connections, rely on sealing systems to maintain pressure containment under service loads. The integrity of sealing systems can be compromised or degraded by excessive wear or mechanical damage. The IM plan for a riser should address sealability in a manner consistent with the design criteria and the expected design life of the sealing system.

Assessments for nonmetallic seals and metallic seals have their own unique characteristics and require different assessment methods.

8.10.2 Retrievable Risers

Retrievable applications allow the user to directly access the sealing systems. Permanent applications require indirect assessment from a qualitative inspection. Although most connection sealing systems are proprietary to the vendor, there are standard methods and common key characteristics that can be verified in the sealing system. Appropriate inspections are needed to provide the necessary data to perform the sealability assessment. The vendor’s verification recommendations should be incorporated into the IM plan.

The following inspection data are recommended for retrievable riser applications:

— retrieved riser equipment traceability data, such as part number;

— sealing diameter;

— axial location of sealing diameter;

— location of damaged area;

— size of damaged area (width, length, depth).

8.10.3 Non-retrievable Risers

Assessment of permanent (non-retrievable) applications is typically limited to pressure tests and visual inspections. In these cases, the user should verify if the system is operating within the design parameters. It is recommended that deviations to the design parameters such as pressure, temperature, or fluid composition should trigger a design reassessment to ensure the sealing system is not compromised under the new service conditions.



8.10.4 Nonmetallic Seals

For nonmetallic seals, the material, and its grade (for example, Nitrile, 70 durometer), extrusion gaps and seal squeeze should be verified to ensure fitness-for-service. Standard O-ring designs can be verified by referring to industry or vendor handbooks for recommended minimum requirements.

8.10.5 Metallic Seals

Metallic seals are typically proprietary to the vendor and require analytical and empirical verification. Sealability of metallic systems are usually characterized by line load. A sealing system’s line load is a function of the interference designed within the sealing system and should have been analytically determined during the design phase to establish dimensional tolerances. In addition, empirical test results should be available to verify that the designer’s minimum line load can maintain sealability and that the maximum line load does not introduce galling.

Any deviation from the design tolerances based on inspections should be revalidated via analysis. Additional testing should be performed if the minimum line load is exceeded based on the inspection data.

In addition, it is important that the profile of the metal seal pocket is maintained within design allowables. Appropriate inspection tools and procedures should be employed to verify any seal pocket rework. The acceptance criteria should be validated with analysis and/or testing to demonstrate the design allowables are maintained.

Sealability of face seals can also be adversely influenced by hub face separation, which is directly related to the connection’s preload. Therefore, it is important to be aware of any changes in the connection makeup.

9 Interfaces

9.1 General

There are key interfaces for risers with other parts of an FPS that should be addressed when developing a riser IM process. The IM of the interfacing systems are not within the scope of this RP, but it can be essential to the riser IM.

9.2 TTR Interfaces

TTR interfaces can include:

— tensioner deck support;

— buoyancy-can guides;

— access platforms;

— jumper to topsides hang-off;

— diverter/bell nipple housing;

— keel guide;

— guidelines and guide-arms;

— subsea wellhead.

The tensioners are usually supported by a platform structure by means of a cassette frame, tendome, or integral to the platform. The platform structure should be assessed for corrosion, indications, or visual damage on a routine



schedule. Riser loads should be reviewed periodically or after an event that would cause a load increase to ensure the platform structure will maintain integrity. Lateral loads from the centralizers or air-can guides should also be reviewed to ensure the design has not been compromised.

Access platforms are important to riser IM. They are used to access riser equipment for inspection and monitoring (e.g. surface trees, casing heads, tensioner joint/rings, etc.). Handrails, grating, and ladders should be routinely inspected for corrosion, indications, or physical damage. Riser angles and/or displacements should be evaluated periodically or after an event that would increase these values to ensure clashing is avoided or mitigated.

On TLPs, TTR installation guidelines can be used to direct the bottom of the riser to the top of the high-pressure wellhead housing for deployments and to ensure that the riser does not clash with neighboring risers during deployments or retrievals. The appropriate guide wire tension should be evaluated periodically as needed. Guide-arm functionality should also be checked to ensure operability is maintained.

The riser imparts loads to the top of the high-pressure subsea wellhead housing, which should be reviewed periodically to ensure the subsea wellhead system’s fatigue and static load capacity has not been exceeded. There are several sensitivities that should be considered, such as wellhead stickup, wellhead angle, cement elevation, and soil stiffness when evaluating the subsea wellhead system’s fatigue and strength performance.

For TTRs, the wellhead and conductor integrity are important. The integrity of those structures as it relates to the external loads is logically part of the riser IM. If that activity is conducted separately, then an interface needs to be established to insure information flows appropriately.

9.3 SCR Interfaces

SCR interfaces requiring IM planning can include the support structure, hull piping, and subsea equipment.

9.3.1 Support Structure

SCRs typically terminate in a stress joint, flexible joint, or pull tube. Stress joints and flexible joints are typically supported by a porch structure that transfers the loads into the platform structure. The structural IM for the porch is addressed in API 2FSIM. Any reassessment of a riser should also include the support structure, as the loads into the structure might have changed.

Pull tube SCRs require special consideration, as the cantilevered portion of the pull tube will absorb the moments from the riser. The interaction between the riser and pull tube is important, and they should be assessed in a single analysis.

Damage or degradation of the support structure should be considered in reassessment of a riser.

9.3.2 Hull Piping

Hull piping refers to the piping that runs from the top termination of an SCR (after the load has been transferred to the hull) to the topsides. In addition to the pressure containment requirements for riser piping, the hull piping is also subject to direct wave and current loading, thermal loading, and any loads imparted by flexure of the platform structure itself. Careful consideration should be given to the structural and mechanical design elements for hull piping. Structural design codes such as API 2A-WSD do not address mechanical design issues or thermal expansion, and, likewise, piping codes do not typically consider wave and current loading.

Most hull piping arrangements include one or more flanged connections between the top termination and the boarding valve on the topsides. Care should be taken to ensure that flange bolts and gaskets are not damaged, and that appropriate assessment is made of the mechanical integrity of the flanges in much the same manner as other parts of the riser.



9.3.3 Subsea Equipment

SCRs typically transition into pipelines on the seabed. At some distance from the touch-down point, the dynamic effects of the riser are no longer relevant and are out of scope for this document. However, consideration should be given to any unique circumstances that might affect the riser. For example, where there is not enough distance after touching down for the riser tension to be taken out by pipe-soil interaction, anchor piles, or pipeline end termination (PLET) structures can be used to resist the load.

Changes in interface loads identified during assessment that could affect pipelines or subsea structures should be considered.

9.4 Hybrid Riser Interfaces

Hybrid risers (e.g. bundled tower riser, single line free standing hybrid riser) typically interface with host FPS by means of flexible jumpers, which are terminated at the host FPS via I-tubes or porches. The integrity assessment of the I-tubes or porches should be part of the host FPS discipline’s responsibility with interface loads provided by riser discipline. The integrity of ancillary equipment, e.g. bend stiffener, are part of the riser discipline work scope.

Riser base jumpers connecting hybrid risers to flowlines are dynamically loaded by the riser, as are the foundations, and hence these should be included in the riser IM scope.

10 Risk Reduction

10.1 General

Risk reduction measures should be considered if a riser does not meet the fitness-for-service performance criteria. Risk reduction should be considered at all stages of assessment and can be used in lieu of more complex assessment.

Risk reduction can include mitigation measures that reduce the exposure of the riser or reduce the likelihood of riser failure.

10.2 Exposure Reduction

Some of the typical mitigation measures may include:

— increased inspection frequency;

— adding VIV suppression;

— adding or replacing anodes;

— adding buoyancy to mitigate fatigue damage accumulation;

— regular cleaning of marine growth;

— availability of spares;

— changes in operating practices, e.g. to reduce corrosion rate, minimize VIV, etc.;

— installation of subsea or platform-mounted safety valves to limit the volume and duration of a release;

— leak detection;

— abandonment of non-producing wells;



— adjustment of TTR tensioner systems to higher tension levels during high-current events that could produce VIV;

— system data availability (e.g. data from production parameters, riser monitoring, inspections, repairs);

— installation of seal clamp around damaged flexible pipe sheath;

— installation of venting clamp below end fitting when flexible pipe vent ports are blocked;

— reduce operating pressure or temperature;

— injection of corrosion-inhibiting chemicals upstream of the riser;

— use of H2S scavengers;

— clear identification of leading indicators for degradation mechanisms for each riser.

For hurricane preparedness, advanced planning can reduce hurricane risks as well as improve post-hurricane response. Written hurricane preparedness plans should be developed covering both general hurricane preparedness activities and riser-specific response activities. Checklists and riser-specific guides can assist during the evacuation process. Platforms with higher life safety, environmental, and/or economic risk can require additional considerations.

Examples of hurricane preparedness activities that can reduce exposure include:

— adjustment of TTR tensioner systems to minimize risk of overload, VIV or VIM;

— blow-down wells to reduce hydrocarbon content of wells;

— developing plans for post-hurricane safe access to the structure should there be damage to a riser;

— developing post-hurricane inspection plans for all risers.

10.3 Likelihood Reduction

The riser fitness-for-service assessment (Section 7 and Section 8) will determine whether strengthening, modification, or repair (SMR) is needed to meet the assessment performance criteria. If SMR are to be considered, the assessment model should be used to develop options.

SMR techniques can include:

— derating the riser to match current reservoir parameters (which may be different from original design);

— replacement of retrievable components;

— refurbishment of retrievable components (e.g. drilling risers), including cleaning, blasting, NDE, replacing, or repairing damaged connectors, etc.;

— refurbishment in place of accessible components (e.g. replace coatings, repair external damage);

— external clamps to immobilize damaged areas (e.g. corrosion, fatigue, dents);

— replacement of top termination for SCRs (i.e. flexible joint, stress joint);

— replacement of top-tensioner components for TTRs;

— cleaning of marine growth.



11 Riser Decommissioning

11.1 General

Decommissioning is a process followed by an owner/operator to plan, gain approval for, and implement the removal, disposal, or reuse of a riser system and associated equipment. The decommissioning of a riser system will generally be part of a larger decommissioning process. For TTR well risers, this would include abandoning the well that it is connected to. For SCRs, it will include decommissioning of the associated pipeline and subsea system. The wells connected to the risers can be abandoned or rerouted to another riser system. This RP only addresses risers.

The riser system is integrated into the host platform, and hence, additional decommissioning requirements can be found in API 2FSIM and API 2SIM. This is particularly relevant for SCRs and flexible risers that have top terminations on the hull below the waterline and rigid hull piping to the topsides.

11.2 Decommissioning Process

The decommissioning process for a riser system involves closing operations through the riser, including permanently abandoning wells that produce through the riser, properly disposing of contents of the riser, removing the riser from the platform, and reusing, abandoning, or disposing of the riser as appropriate. Similarly, any associated equipment should be decommissioned and disposed of appropriately.

11.2.1 Pre-decommissioning Data Gathering

Relevant data should be collected well ahead of decommissioning to gain knowledge of the riser and associated wells, pipelines, and subsea equipment. The IM strategy should integrate with the decommissioning planning process to align late life inspections to collect the condition data relevant to decommissioning. A well-thought-out IM strategy should make the relevant data readily available. This might not be the case if the IM strategy was not in place over the life of the riser, and additional effort will be required.

Important data include:

— original design data;

— modifications or equipment change-out;

— changes in operational conditions over the life of the riser;

— known anomalies and risks.

11.2.2 Planning and Engineering

Data collected from the pre-decommissioning activities are used to develop the decommissioning plan. Sufficient engineering should be performed to allow selection of the preferred execution plan to verify that environmental and life safety risk considerations are adequately addressed.

A decommissioned riser can provide valuable data for calibration of design assumptions and methodologies, inspection results, and any monitoring data collected. For example, comparing actual corrosion to predicted corrosion and original corrosion assumptions can provide valuable guidance for future riser fitness-for-service assessments under similar conditions.

The IM strategy should include some guidelines or recommendations for forensic investigations of decommissioned riser or riser components.


46

Annex A(informative)

Assessment Method Examples

These examples are not exhaustive. They are selected based on the most common occurrences that do not have a clear path forward to assess fitness-for-service.

All equations, figures, tables, and paragraphs/sections referenced in this annex refer to those in API 579-1/ASME FFS-1, June 2007, unless explicitly noted otherwise.

A.1 Assessment of Localized Thin Areas

Example Problem:

Inspection of a pulled drilling riser indicates a region of localized wear on the inside surface of the inner riser at an elevation of 16 ft above the mudline. Somewhat uniform wall loss due to corrosion is observed in other parts of the inner drilling riser as well. The drilling riser has been in service for a cumulative period of 3 years. The design service life of the drilling riser is 6 years.

The drilling riser is designed to API 2RD. Evaluate the region of localized and uniform wall loss for pressure plus supplemental loads, and determine acceptability for continued operation without repairs.

Example Solution:

PART 1 Wall Loss Measurement

The inner drilling riser wall loss at the worn-out area should be measured by a suitable means of measurement. Guidance on wall thickness is given in 4.3.3.

Design wear allowance (DWA) for 20 years’ service 0.125 in.Design corrosion allowance (DCA) for 20 years’ service 0.0 in.Uniform wall loss (LOSS) 0.05 in.Highest localized wall loss (LWL) 0.17 in.

PART 2 Initial Wall Thickness Assessment

Wall Loss Comparison with DCA

The highest measured wall loss should be compared against the DWA + DCA assumed during the design of the riser. If the wall loss is greater, further investigation should be carried out. Level 2 assessment rather than Level 1 assessment will be necessary due to the presence of loads other than pressure loading.

0.05 < (DWA + DCA = 0.125 in.) < 0.17 in.

The coefficient of variation (CV) of the wall thickness is found to be greater than 10 %. Therefore, critical thickness profiles (CTPs) will be required.

Calculation of Future Wear and Corrosion Allowance

For the inner drilling riser, the expected corrosion rate is found to be zero by the corrosion expert if corrective actions are taken to ensure that the chemistry of the drilling mud is non-corrosive for the riser and proper storage facilities for



the riser to prevent moisture from causing wall loss due to rusting. But for the purposes of conservatism, the corrosion expert assigns the future corrosion allowance (FCA) = 0.04 in. since uniform corrosion did occur.

Future wear allowance (FWA) + FCA = DWA + DCA − LOSS

FWA = 0.125 + 0.0 − 0.05 − 0.04 = 0.035 in.

Future corrosion allowance (FCA) 0.04 in.Future wear allowance (FWA) 0.035 in.

Rate of Wall Loss

If FWA + FCA < rate of wall loss (RWL) × time of riser service remaining (TRSR), an inspection program at a suitable frequency should be set up to monitor the wall loss. Level 2 assessment for LOSS is necessary.

Even if FWA + FCA > RWL × TRSR, an inspection program at a suitable frequency is recommended to monitor the RWL.

RWL = LOSS / time elapsed = 0.05 / 3 = 0.017 in./year

TRSR = design life − time elapsed = 6 − 3 years = 3 years

(FWA + FCA = 0.075 in.) > (RWL × TRSR = 0.05 in.). Rate of LOSS is acceptable.

The localized wear rate is higher than acceptable. Therefore, the inner drilling riser joint to have undergone the wear will need to be switched with another riser joint at a different location along the riser string.

PART 3 Level 2 Assessment

Data Collection

A Level 2 assessment is performed in accordance with 5.4.3.2, due to the presence of loads other than the pressure loading. The inner riser loads at the new location of the inner riser joint from the analysis performed during the design phase are compiled along with other important riser parameters. The new elevation of the inner drilling riser LWL will be 100 ft below the MWL.

Environmental DataWater Depth 4000 ftMud Density 10 ppgMud Temperature 50 °C

Inner Riser Pipe DataMaterial Grade API Spec 5CT L80Pipe Construction Seamless, 40 ft joints, threaded and coupledNominal Dimensions 16 in. OD × 1 in. WTSMYS, Sy 80 ksiSMTS 92 ksi

Critical Strength Loads Obtained from Design Phase Analysis Report at Wear LocationNormal Operating Condition

Maximum Effective Tension 50 kipsPredicted Bending Moment, Mx 60 ft-kips



Detailed Inspection Data

Detailed inspection data are collected in accordance with the procedure given in 4.3.3.3. The thickness data and the grid used for the inspection are shown in Figure A.1 and Table A.1 below. This is the only region of localized metal loss found in the inner riser during inspection. The distance from the region of local metal loss to the nearest coupling is Lmsd = 10 ft. There is no other structural discontinuity in the vicinity.

Assessment Method

trd tnom LOSS– 1.0 0.95– 0.95 in.= = =

tc tnom LOSS– FCA– FWA 0.95 0.04– 0.035– 0.875 in.= =–=

STEP 1 Determine the CTPs in accordance with 5.3.3.2.

STEP 2 Determine the wall thickness to be used in the assessment using Equations 5.3 and 5.4.

Predicted Bending Moment, My 30 ft-kipsPredicted Shear Force 100 kipsPredicted Torsional Moment 5 ft-kipsPressure Loading 5000 psiAllowable von Mises Stress 53.6 ksi (0.67 × Sy in accordance with API 2RD)Internal Fluid Pressure 5000 psi defined 120 ft above MWL

Extreme ConditionMaximum Effective Tension 150 kipsPredicted Bending Moment, Mx 100 ft-kipsPredicted Bending Moment, My 50 ft-kipsPredicted Shear Force 112 kipsPredicted Torsional Moment 10 ft-kipsPressure Loading 5000 psiAllowable von Mises Stress 64.00 ksi (0.80 × Sy in accordance with API 2RD)Internal Fluid Pressure 5000 psi defined 120 ft above MWL

Survival ConditionMaximum Effective Tension 200 kipsPredicted Bending Moment, Mx 136 ft-kipsPredicted Bending Moment, My 70 ft-kipsPredicted Shear Force 150 kipsPredicted Torsional Moment 17 ft-kipsPressure Loading 1000 psiAllowable von Mises Stress 80.00 ksi (1.00 × Sy in accordance with API 2RD)Internal Fluid Pressure 1000 psi defined 120 ft above MWL


Figure A.1—Inspection Grid for Wall Thickness Measurements at LWL Area

Table A.1—Measured Wall Thicknesses in Local Thin Area (LTA)

Inspected Wall Thickness (in.)

Longitudinal Inspection

Planes

Circumferential Inspection Planes Circumferential CTPsC1 C2 C3 C4 C5 C6 C7

M1 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

M2 1.00 0.95 0.91 0.89 0.93 0.98 1.00 0.89

M3 1.00 0.92 0.90 0.85 0.90 0.95 1.00 0.85

M4 1.00 0.91 0.87 0.83 0.88 0.91 1.00 0.83

M5 1.00 0.94 0.89 0.88 0.85 0.89 1.00 0.85

M6 1.00 0.96 0.95 0.93 0.90 0.94 1.00 0.90

M7 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

Longitudinal CTP 1.00 0.91 0.87 0.83 0.85 0.89 1.00

tmm 0.83 in.=

s 6 1 6 in.=×=


STEP 3 Determine the minimum measured thickness, tmm, and the dimension, s, for the longitudinal CTP (see Figure A.2). There is only one LTA in the riser. Therefore, the spacing criteria in 4.3.3.3.f.3 of Part 4 do not need to be checked.

NOTE 1 Spacing of thickness readings in longitudinal direction is 1.0 in.

NOTE 2 Spacing of thickness readings in circumferential direction is 3.0 in.

NOTE 3 CTP is critical thickness profile.



STEP 4 Determine the remaining thickness ratio and the longitudinal flaw length parameter, λ using Equations 5.5 and 5.6.

Rt = (tmm − FCA − FWA) / tc = (0.83 − 0.04 − 0.035) / 0.875 = 0.863

Inner diameter, D = 14 + 2 × (FCA + FWA) = 14.15 in.

λ 1.285 s D tc×( )⁄× 1.285 6( ) 14.15 0.875( )( )⁄ 2.191= = =

STEP 5 Check limiting flaw size criteria for a Level 1 Assessment using Equations 5.7, 5.8, and 5.9.

(Rt = 0.863) ≥ 0.20 True

(tmm − FCA − FWA = 0.755 in.) ≥ 0.10 in. True

Lmsd 10 ft=( ) 1.8 D tc×( ) 1.8 14.15 0.875( )( ) 6.33 in.= =( )> True

Mean radius of pipe, Rm

D2---- FCA– FWA tnom+– D

2----+

2-----------------------------------------------------------------------

14.152

-------------- 0.04– 0.035– 1.0+ 14.15

2--------------+

2---------------------------------------------------------------------------------------------- 7.5375 in.= = =

R D

2---- 14.15

2-------------- 7.075 in.= = =

STEP 6 Check the criterion for a groove-like flaw. This step is not applicable because the region of LWL is categorized as a localized thin area (LTA).

STEP 7 Determine the maximum allowable working pressure (MAWP) for the component using Equations (A.10), (A.16) and (A.22).

Normal Operating Condition

Supplemental thickness for axial stress calculations, tsl =

F2SEπRm---------------------- M

SEπRm2

-------------------+ 502 53.6( ) 1.0( )π 7.5375( )------------------------------------------------------------ 12( ) 602 302+

53.6( ) 1.0( )π 7.5375( )2

---------------------------------------------------------- 0.1038 in.=+=

MAWP based on CTP,

Figure A.2—Longitudinal CTP

s 6.0 in.

1.00 in.


MAWPC SEtc

R 0.6tc+---------------------- 53.6( ) 1.0( ) 0.875( )

7.7075( ) 0.6 0.875( )+--------------------------------------------------------- 5.697 ksi 5697 psi.= = = =


MAWP based on LTP,

MAWPL 2SE tc tsl–( )

R 0.4 tc tsl–( )–------------------------------------ 2 53.6( ) 1.0( ) 0.875 0.1038–( )

7.7075( ) 0.4 0.875 0.1038–( )–--------------------------------------------------------------------------------- 11.173 ksi 11 173 psi.,= = = =

MAWPnormal operating min MAWPC MAWPL,[ ] 5697 psi.= =

Extreme Condition


F2SEπRm----------------------- M

SEπRm2

-------------------+ 1502 64( ) 1.0( )π 7.5375( )------------------------------------------------------- 12( ) 1002 502+

64( ) 1.0( )π 7.5375( )2

----------------------------------------------------- 0.1669 in.=+=

MAWP based on CTP,

MAWPC SEtc

R 0.6tc+---------------------- 64( ) 1.0( ) 0.875( )

7.7075( ) 0.6 0.875( )+--------------------------------------------------------- 6.802 ksi 6802 psi.= = = =

MAWP based on LTP,


R 0.4 tc tsl–( )–------------------------------------ 2 64( ) 1.0( ) 0.875 0.1669–( )

7.7075( ) 0.4 0.875 0.1669–( )–--------------------------------------------------------------------------------- 12.208 ksi 12 208 psi.,= = = =

MAWPextreme min MAWPC MAWPL,[ ] 8503 psi.= =

Survival Condition


F2SEπRm----------------------- M

SEπRm2

-------------------+ 2002 80( ) 1.0( )π 7.5375( )------------------------------------------------------- 12( ) 1362 702+

80( ) 1.0( )π 7.5375( )2

----------------------------------------------------- 0.1813 in.=+=

MAWP based on CTP,

MAWPC SEtc

R 0.6tc+---------------------- 80( ) 1.0( ) 0.875( )

7.7075( ) 0.6 0.875( )+--------------------------------------------------------- 8.503 8503 psi.= = = =

MAWP based on LTP,


R 0.4 tc tsl–( )–------------------------------------ 2 80( ) 1.0( ) 0.875 0.1813–( )

7.7075( ) 0.4 0.875 0.1813–( )–--------------------------------------------------------------------------------- 14.938 ksi 14 938 psi.,= = = =

MAWPsurvival min MAWPC MAWPL,[ ] 8503 psi.= =

STEP 8 Determine the remaining strength factor (RSF) for the longitudinal CTP. Using Table 5.2 and Equation 5.11:

For λ = 2.191, Mt = 1.709


RSFRt

1 1Mt

------ 1 Rt–( )–----------------------------------- 0.863

1 11.709--------------- 1 0.863–( )–

----------------------------------------------------- 0.938= = =

RSFa 0.9=( )>


STEP 9 Since RSF > RSFa, the MAWP does not need to be reduced.

Internal to external pressure differential at the location of the LWL in normal operating condition,

Internal pressure, Pi = 5000 + (120 ft + 100 ft) (74.8 lb/ft3) / 144 = 5144.3 psig

External pressure, Po = (100 ft) (64 lb/ft3) / 144 = 44.4 psig

MAWPnormal operating 5697 psi= ) Pi Po– 5069.8 psi=( )>

The longitudinal extent of the flaw is acceptable in normal operating conditions. It can be shown using a similar approach that the longitudinal extent of the flaw is acceptable in extreme and survival conditions as well.

Therefore, a remaining strength factor based on Level 2 assessment is not necessary.

Amπ Do

2 D2–( )

4-------------------------- π 162 14.152–( )

4--------------------------------------- 43.8075 in.2= = =

STEP 10 Evaluate the circumferential extent of the flaw in accordance with paragraph 5.4.3.4.

STEP 10.1 For the circumferential inspection plane being evaluated, approximate the circumferential extent of metal loss on the plan under evaluation as a rectangular shape (Figure 5.11). Calculate Df using Equation 5.23 and θ using Equation 5.25.

Do = 16 in.

STEP 10.2 Compute the components of the resultant longitudinal bending moment excluding torsion in the plane of the defect relative to the region of metal loss. In this case, the moments stated in the problem were aligned with the flaw. In general, the moments will not be aligned with the flaw, and the moments results obtained from a stress analysis during design phase will need to be resolved to the axis of the flaw as shown in Figure 5.11.

STEP 10.3 Compute the circumferential stress at points A and B in the cross-section (Figure 5.12) using Equation 5.26.

STEP 10.4 Compute section properties (use equations in Table 5.3) and the longitudinal membrane stress and shear stress at points A and B in the cross-section.

STEP 10.4.1 Compute section properties of the riser without an LTA.

Df Do 2– tmm FCA FWA––( ) 16 2– 0.83 0.04– 0.035–( ) 14.49 in.= = =

c 6 3× 18.0 in.= =

θc

Df---- 18

14.49--------------- 1.242 radians= = =

σcmMAWPnormal operating

RSF--------------------------------------------- D

Do D–---------------- 0.6+ 5697

0.938-------------- 14.15

16 14.15–-------------------------- 0.6+ 50 099 psi,= = =

AaπD2

4--------- π 14.15( )

2

4------------------------- 157.2544 in.2= = =


Ixπ Do

4 D4–( )

64-------------------------- π 164 14.154–( )

64--------------------------------------- 1249.1243 in.4= = =

Iy Ix 1249.1243 in.4= =

Afθ Df

2 D2–( )

4-------------------------- 1.242 14.492 14.152–( )

4----------------------------------------------------------- 3.0235 in.2= = =

Aw Aa Af+ 157.2544 3.0235+ 160.2779 in.2= = =

y112------ sin θ[ ] Df

3D

3–( )

Am Af–--------------------------------------- 1

12------ sin 1.242[ ] 14.493 14.153–( )

43.8075 3.0235–------------------------------------------------------------------------ 0.4045 in.= = =

xA 0.0 in.=

yA y Do

2------+ 0.4045 16

2------+ 8.4045 in.= = =

xBDosin θ[ ]

2---------------------- 16( ) 0.946432( )

2----------------------------------------- 7.5715 in.= = =

yB y Docos θ[ ]

2------------------------+ 0.4045 16( )cos 1.242[ ]

2----------------------------------------+ 2.9877 in.= = =

b112------ sin θ[ ] Df

3D

3–( )

Aa Af–---------------------------------------- 1

12------ sin 1.242[ ] 14.493 14.153–( )

157.2544 3.025+------------------------------------------------------------------------- 0.10293 in.= = =

RDf

2----- 14.49

2-------------- 7.245 in.= = =

dDf D–( )

2-------------------- 14.49 14.15–

2----------------------------------- 0.17 in.= = =

Atfc Df Do–( )

8------------------------- 18 14.49 16+( )

2--------------------------------------- 274.41 in.2= = =


STEP 10.4.2 Compute section properties for cylinder with LTA on inside surface.

with,

yLX2R sin θ[ ]

3θ------------------------- 1 d

R---– 1

2 d

R---–

------------+ 2 7.245( ) sin 1.242[ ]

3 1.242( )---------------------------------------------------- 1 0.17

7.245--------------– 1

2 0.0177.245--------------–

------------------------+

5.4563 in.= = =

ILX 6.56984 in.4=

IX

IX Amy2ILX– Af yLX y+( )

2–+ 1145.8681 in.4= =

ILY 58.43964 in.4=

IY

IY ILY– 1190.6847 in.4= =

At0.5π D Do+( ) c–[ ] D Do+( )

8-------------------------------------------------------------------- 110.6487 in.2= =


λC1.285cDtc

----------------- 1.285( ) 18( )

14.15( ) 0.875( )------------------------------------------- 6.5735= = =

Mt

C 1 0.1401 λC( )2 0.002046 λC( )

4+ +1 0.09556 λC( )

2 0.0005024 λC( )4+ +

------------------------------------------------------------------------------------------- 1.79225= =

MsC

1 1Mt

C------- d

tc--- –

1 d

tc--- –

---------------------------------1 1

1.79225--------------------- 0.17

0.875-------------- –

1 0.170.875-------------- –

---------------------------------------------------------- 1.1066= = =

σlmA Ms

C

Ec-------- Aw

Am Af–---------------- MAWP( )

FT

Am Af–---------------- yA

IX

---- FTy y b+( ) MAWP( )Aw Mx++[ ]xA

Iy----My+ + +

=

1.10661.0

----------------- 160.277943.8075 3.0235–---------------------------------------------

5697( )

50 000,43.8075 3.0235–--------------------------------------------- 8.4045

1145.8681---------------------------- 50 000,( ) 0.4045( )[+ +=

+ 0.4045 0.10293+( ) 5697( ) 160.2779( ) 60 000,( ) 12( )] + 0.01190.6847---------------------------- 30 000,( ) 12( )

+

35= 900.74 psi,

σlmB Ms

C

Ec-------- Aw

Am Af–---------------- MAWP( )

FT

Am Af–---------------- yB

IX

---- FTy y b+( ) MAWP( )Aw Mx++[ ]xB

Iy----My+ + +

=

1.10661.0

----------------- 160.277943.8075 3.0235–---------------------------------------------

5697( )

50 000,43.8075 3.0235–--------------------------------------------- 2.9877

1145.8681---------------------------- 50 000,( ) 0.4045( )[+ +=

+ 0.4045 0.10293+( ) 5697( ) 160.2779( ) 60 000,( ) 12( )] + 7.57151190.6847---------------------------- 30 000,( ) 12( )

+

32= 137.96 psi,

τMT

2 At Atf+( ) tmm FCA– FWA–( )-------------------------------------------------------------------------= V

Am Af–----------------+

12( ) 5000( )

2 110.6487 274.41+( ) 0.83 0.04– 0.035–( )----------------------------------------------------------------------------------------------------------------= 100 000,

43.8075 3.0235–---------------------------------------------+

2555.134 psi=

σeA

σcm( )2

σcm( ) σlmA

( )– σlmA

( )2 3τ

2+ + 44 942 psi,= =


STEP 10.4.3 Compute the longitudinal membrane stress and shear stress at points A and B in the cross-section using Equations 5.27 to 5.32.

STEP 10.4.4 Compute the equivalent membrane stress at points A and B in the cross-section using Equations 5.33 and 5.34.


σeB

σcm( )2

σcm( ) σlmB

( )– σlmB

( )2 3τ

2+ + 44 185 psi,= =

max σeA

σeB

,[ ] 44 942,={ } HfSa

RSFa------------ 1.0( )

53 600,0.9

------------------ 59 556,= =

≤


STEP 10.4.5 Evaluate the results using Equation 5.35.

The circumferential extent of the flaw is acceptable for the normal operating loads. It can be shown that the flaw is acceptable for extreme and survival load conditions as well.

Therefore, the inner riser joint is acceptable for continued operation without repair or replacement.

A.2 SCR Life Extension Assessment

A deepwater 10 in. diameter oil production SCR suspended from a semi-submersible has been in operation for 15 years. Originally the riser was designed for 25 year service. The operator would like to extend the life of the riser for 5 more years. The operator has performed periodic ROV surveys, and no assessment triggers were observed from the ROV visual inspections. Recently an in-line inspection (ILI) was performed, which showed a corrosion-like feature in the parent material of the riser near the touch down region, about 100 m from the nominal TDP. Based on the ILI data, the feature appears to be 3 mm deep and 30 mm long. No ILI was performed after installation, so it is unknown if this feature was pre-existing or has developed during operation over the last 15 years. During the design phase, the corrosion allowance was taken as 5 mm. The operator has collected production fluids periodically for the last 15 years and has performed laboratory material testing to determine appropriate fatigue knock-down factors on the base metal and the welds due to the corrosive production fluid. This example demonstrates the application of fitness-for-service assessment methods for the following failure mechanism.

— general corrosion estimates based on production fluid chemistry for the next 5, 10, and 15 years;

— fatigue assessment of the welds based on new knockdown factor;

— fracture mechanics or fatigue assessment of the base metal in the corrosion feature.

A.3 Sealability Assessment

For assessing sealability, the following should be considered:

a) Application: Drilling riser flange seals and seal pockets;

b) Trigger: Mechanical damage during handling of joint or running/retrieval operations;

c) Inspection recommended: Perform dimensional inspection of seal or seal pocket to determine diameter, location and overall characteristics (depth and length) of affected area;

d) Assessment method:

1) For nonmetallic seals, determine seal squeeze and extrusion gaps based how much material needs to be removed to eliminate defect. These values need to be verified with minimum acceptable values.

2) For metallic seals, review analysis results to determine minimum acceptable line load based on minimum interference. If required material removal exceeds minimum interference, additional analysis should be considered to validate the minimum acceptable line load is satisfied. Deviations from minimum acceptable line load should be verified with appropriate testing.


56

Annex B(informative)

Commentary Additional Information and Guidance

The sections in this annex provide additional information and guidance on the main text of this RP. The title of each subheading identifies the subsection of the RP to which it relates guidance is only offered on the identified sections.

B.1 Riser Monitoring Considerations (see 5.3.2)

For example, there is often uncertainty over reservoir fluid properties and how they can change over time. If the design is based on a certain level of H2S, monitoring of H2S over the life will help the operator understand if the actual corrosion and fatigue damage will be above or below the level required to demonstrate fitness-for-service.

Another example might be a novel riser or platform configuration for which there is uncertainty over the dynamic performance—meaning the inference of riser motions from platform motions could not be accurate. In this case, additional monitoring of the dynamic performance of the riser itself could be important.

B.2 Life Extension (see 7.2.2)

A life extension assessment is essentially the same as a fitness-for-service assessment except that the service life is increased.

In some instances, the original design can be robust enough to reach a longer service life without additional work due to conservatism in the original design, due to:

— improvements in design methodologies or criteria since the original design was executed;

— changes in operating parameters;

— IM data that show less degradation than anticipated or less severe service than anticipated (e.g. S-N curve selection based on reservoir souring that never occurs, or riser motion monitoring that indicates lower fatigue cycles than included in the design)

EXAMPLE 1 SCR designed to API 2RD with a design service life of 20 years. The calculated minimum fatigue life was 24 years at the time of design. With no unfavorable changes to the operating envelope, this riser could be extended to 24 years.

EXAMPLE 2 TTR designed to API 2RD with a design service life of 20 years. The calculated minimum fatigue life at the time of design was 20 years for the tensioner joint at the top of the riser and for the stress joint at the base of the riser, but well in excess of 50 years for the other components. With replacement of the tensioner and stress joints at year 20, the riser could be extended well beyond 20 years.

EXAMPLE 3 SCR designed to API 2RD with a design service life of 20 years. The original design criteria included a combination of fatigue S-N curves corresponding to no souring for the first 10 years and mildly sour service for the second 10 years. Through fluid monitoring, it is determined that souring did not occur until year 15. A reassessment of the fatigue life, taking this into account, could result in a significant extension of the service life of the riser at year 20.

EXAMPLE 4 SCR designed to API 2RD with a design service life of 20 years. The fatigue damage of the most critical location shows a life of just over 20 years. However, VIV accounts for a considerable portion of the predicted fatigue damage. The current conditions at the platform are closely monitored, along with other metocean conditions and the platform motions. After 15 years, a fitness-for-service assessment is performed to determine remaining life. It turns out there have been significantly less VIV events (high currents) than projected, and the estimated fatigue damage already incurred is considerably less than expected at year 15. A trigger is added for any high current event over a certain duration. If these events occur, the fatigue damage incurred is calculated and accumulated, and the remaining life estimate is updated accordingly. If the damage is more than projected, the remaining life could be less than the planned service life, in which case repair, remediation, or replacement could be needed to reach the planned service life, or it could show even longer anticipated fatigue life.



B.3 Special Inspections (see 6.2.5.5)

B.3.1 Extreme Environmental Event

Inspection should be performed after exposure to an extreme environmental event that has the potential for exceeding the design loads, e.g. extreme storm, hurricane, high current event. The minimum scope should consist of the following:

a) a visual inspection of all the above water riser system components;

b) a visual inspection (without marine growth cleaning) that provides full coverage, 360 degree and from boundary to boundary of riser system;

c) a visual confirmation of the condition of the CP system and any appurtenances (VIV suppression, buoyancy modules, etc.).

B.3.2 Accidental Loading

A focused visual inspection should be performed above and below water after accidental loading that could lead to riser damage, such as boat collision, dropped object, anchor drag, etc. The inspection should be performed as soon as practical after the occurrence of the accidental loading event. Inspection should be performed to establish the extent of any damage.

While the primary focus of the inspection should be near the impact area, the inspection should also look for indirect signs of damage away from the location of impact, such as localized areas of missing marine growth. For example, a boat collision might cause dynamic loading that could shake loose VIV suppression, anodes, or marine growth at another location, or a potential anchor drag event on the flowline some distance away from a catenary riser could disturb the seabed either side of the touch down region, which should be inspected.

B.4 Riser Monitoring (see 6.3)

B.4.1 Riser Monitoring Considerations

Riser monitoring can vary with the type of riser, which can be broadly classified as follows:

— steel catenary risers (SCRs);

— top tension risers (TTRs);

— hybrid risers;

— flexible risers.

Ideally, the combination of the design and construction data, baseline inspections, in-service inspections, and monitoring should give a complete enough picture of the present condition to make reasonable judgment on fitness for service. Selecting the appropriate level of monitoring will depend on where the gaps are in the rest of the data, weighed against the potential consequences absent monitoring data.

The level of monitoring depends on the level of confidence in the design and understanding of the design uncertainties and the resulting risk. Changes during operations can influence monitoring requirements. Table B.1 summarizes the typical riser monitoring considerations for each type of riser.

Level 1 operational monitoring data are used by the operations team for optimizing production and safety, including real time alerts. Level 2 condition monitoring data are generally long-term trending data used for IM evaluation.


Table B.1—Riser Monitoring Considerations

Riser Type Level 1—Operational Monitoring a Level 2—Risk-based Condition Monitoring

All risers

— Metocean conditions

— Platform six degree of freedom motions b

— Platform mass and CG

— Surface pressure and temperature

— Subsea pressure and temperature

— Fluid properties

— Sand content

—

TTR

— Top tension

— Annulus pressures

— Tensioner cylinder pressure or air can pressure

— Riser stroke

— Riser guide clearance (buoyancy can application)

Hybrid

— Tension/buoyancy load

— Displacement

— Extreme loading

— Flexible pipe annulus conditions (vent rate monitoring, gas sampling, annulus vacuum, and/or positive pressure testing)

— Polymer coupon sampling c

Flexible riser —— Annulus conditions (vent rate monitoring, gas sampling,

annulus vacuum, and/or positive pressure testing)

— Polymer coupon sampling c


Additional monitoring can be useful to mitigate risks that might arise because of either uncertainty at the design stage (e.g. fluid properties, environmental loads, platform motions, riser response), or because the riser includes a novel configuration, materials, equipment, analysis, or installation techniques that have not been used previously by industry or the owner/operator. In such cases, additional monitoring might be considered for design verification.

B.4.2 Direct Riser Monitoring Systems

Riser monitoring systems can be categorized into three types:

— Autonomous (offline): Stand-alone power and data storage retrievable by ROV;

— Semi-autonomous: Stand-alone power, semi-continuous data transmission by acoustic modem;

— Online: Real-time continuous power supply and data transmission.

The type of system selected depends on the location of the power supply, communication maintenance required, and proximity to the platform. It also depends on the intended use of the data in the IM plan. Online systems are ideal because the data are always available, but not all measurements are needed in real time, and in many cases, it is impractical to use anything but autonomous systems. In any case, the availability of data should be taken into consideration in developing the IM plan. Riser monitoring systems can be permanent systems intended for long-term riser monitoring, or they can be temporary systems intended to measure data for a specific period to meet an objective.

a For Level 1, where data are not available, alternative methods or inference can be considered.

b Motions of the riser due to environmental loads can generally be inferred from platform motions and metocean data.c Monitoring conveyed fluid characteristics is more effective than polymer coupon sampling.



In practice, due to the harsh environment that risers are deployed in, a permanent riser monitoring system that can remain operational for the full riser service life might be impractical, or at best, challenging to maintain. The requirement for a long-term monitoring system can be beneficial and should be defined during the design phase, or in the operation phase where an anomaly has been identified, or to confirm suitability for life extension.

Temporary riser monitoring systems can be required during installation phase (e.g. buoyancy tank and riser tension of FSHR) or can be deployed in-service to collect data as part of an anomaly evaluation, reassessment, or calibration of analytical methods.

B.5 Factors That Affect Riser Global Analysis (see 8.6.1)

B.5.1 General

Provided are recommendations on how to address various factors that affect riser strength and fatigue assessment from a global analysis perspective, including: platform configuration, riser top tension, hydrodynamic coefficients, and soil interaction.

B.5.2 Platform Configuration

Several platform configurations are likely to occur during the service life of a given riser system. Any parameter that affects the platform motions, offset or draw-down can affect the global behavior of a riser. Various configurations can include differences in the number and size of installed risers, drilling rig installed or removed, mooring system pretension, mooring system position, platform weight and vertical center of gravity (VCG), platform draft, and platform wind profile. For a TLP, seabed subsidence can increase the draft of the platform over time.

The original design should have taken into consideration all anticipated platform configurations in developing the design load cases, so reassessment would be triggered only by changes from the initial cases considered. Although it is essential to identify changes that increase the loading on a riser, it is also possible that the way a platform is operated reduces the loading on a riser, which could give flexibility in accommodating other initiators.

Typically, the controlling design load case for strength will be with maximum topsides payload and the highest VCG, which typically includes the drilling rig and all risers installed. Before all risers are installed, the platform will normally carry the remaining riser payload as ballast low in the hull, so installing each TTR increases the VCG. Risers supported below the waterline are typically neutral in this regard, but all risers add lateral stiffness, reducing offset.

If risers are installed in a phased program over multiple years, the fatigue calculation can use multiple platform configurations, along with a conservative estimate of the time duration in each configuration. The fatigue damage for each platform configuration can be linearly superimposed to determine the overall calculated fatigue life. Alternatively, for fatigue calculations, it is permissible to use a single platform configuration (number of risers) if it can be demonstrated that the resulting life prediction is conservative compared to the result with multiple platform configurations

B.5.3 Riser Top Tension

Riser top tension is selected to prevent riser instability, resist environmental loading and fatigue, avoid riser interference, and minimize platform payload.

Factors affecting riser tension include: water depth, wet weight of all riser tubulars, weight of equipment above the tensioner load ring, fluids in each riser annulus and production tubing, tensioning system spring stiffness, possible failure modes, and riser interference.



For design purposes, riser top tension is typically expressed as the ratio of riser top tension to riser wet weight. This ratio is termed top tension factor (TTF) and is defined as follows in Equation B.1:

TTFT WT–WR

-------------------= (B.1)

Where T is the total vertical force reacted by the tensioner system, WT is the weight of all components above the tensioner attachment, and WR is the wet weight of riser below tensioner attachment. The nominal TTF is the intact, static TTF with no environmental forces applied.

Tension factor varies with riser type and service condition and should be defined for each load case. If possible, actual tension factor values should be used in the analysis.

B.5.4 Hydrodynamic Coefficients

Guidelines for drag and added mass coefficients to be used for various ranges of seastates can be found in the literature. The appropriate coefficients depend on the flow regime. This can be significant when considering extreme seastates vs everyday fatigue seastates.

Marine growth should be considered in calculating hydrodynamic loads on risers. Inspection reports should be consulted to determine the extent of the marine growth present on the riser. Hence, a history of marine growth based on inspections can be important to assessment of risers.

The appropriate drag coefficients for VIV suppression should come from model testing and take into account the extent of marine growth present.

B.5.5 Soil Interaction

The riser analysis model at the subsea wellhead interface for TTRs or the touch-down point for pipeline risers should consider interaction with the soil. The riser-soil interaction can be modeled using springs based on p-y data for the soil. The riser-soil interaction is generally important for the following design cases:

— the extreme response of the riser when the floating platform has moved a considerable distance from the mean position under extreme weather conditions;

— the fatigue damage prediction because of repeated cyclic motions with a range of amplitudes and frequencies.

Since the characterizations of the soil for large deformation (extreme responses) and for small repetitive deformation (fatigue) are different, care should be taken in selection of the appropriate soil properties, and a geotechnical expert should be consulted. It is recommended that the most likely soil properties be used.

B.6 Corrosion Control (see 8.8)

The most likely cause of failure in a steel riser is corrosion. The IM plan should include a written and auditable corrosion control plan. The IM plan should verify that the corrosion control plan is being followed and should track the inputs that affect the corrosion rates (fluid composition, chemistry, pressure and temperature, inhibitor availability and effectiveness) as well as the measurement of corrosion by coupons, probes, ILI, and external inspection.


61

Bibliography

[1] Stelios Kyriakides and Edmundo Corona 1, Mechanics of Offshore Pipelines: Volume 1 Buckling and

Collapse, 2007, https://doi.org/10.1016/B978-0-08-046732-0.X5000-4

[2] API Recommended Practice 2A-WSD, Planning, Designing and Constructing Fixed Offshore Platforms—

Working Stress Design

[3] API Recommended Practice 2FSIM, Floating Systems Integrity Management

[4] API Recommended Practice 2MET, Derivation of Metocean Design and Operation Conditions

[5] API Recommended Practice 2MIM, Mooring Integrity Management

[6] API Recommended Practice 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg

Platforms (TLPs), 1st Edition

[7] API Recommended Practice 2SIM, Structural Integrity Management of Fixed Offshore Structures

[8] API Recommended Practice 17B, Flexible Pipe

[9] API Recommended Practice 17L2, Flexible Pipe Ancillary Equipment

[10] API Recommended Practice 579-1/ASME FFS-1, Fitness-for-Service

[11] API Recommended Practice 579-1/ASME FFS-1, Fitness-for-Service, June 2007

[12] API Specification 17J, Unbonded Flexible Pipe

[13] API Specification 17K, Bonded Flexible Pipe

[14] API Specification 17L1, Flexible Pipe Ancillary Equipment

[15] API Standard 2RD, Dynamic Risers for Floating Production Systems

[16] API Standard 7CW, Casing Wear Tests

[17] ASME Boiler and Pressure Vessel Code 2, Section VIII, Division 2

[18] ASME Boiler and Pressure Vessel Code, Section VIII, Division 3

[19] ASME Boiler and Pressure Vessel Code, Section VIII, Division 3, Article KD-4, 2017

[20] BS 7608 3, Guide to Fatigue Design and Assessment of Steel Products

[21] BS 7910, Guide to Methods for Assessing the Acceptability of Flaws in Metallic Structures

[22] DNV-OS-F101 4, Submarine Pipeline Systems

1 Elsevier B.V., Radarweg 29, 1043 NX Amsterdam, The Netherlands, www.elsevier.com.2 American Society of Mechanical Engineers (ASME), Two Park Avenue, New York, New York, 1001-5990, www.asme.org.3 British Standards Institution (BSI), 389 Chiswick High Road, London, W4 4AL, UK, www.bsigroup.com.4 Det Norske Veritas (DNV), 1400 Ravello Drive, Houston, Texas, 77449, www.dnvgl.com.



[23] DNV-OS-F201, Dynamic Risers

[24] DNV-RP-C203, Fatigue Design of Offshore Steel Structures

[25] DNV-RP-F203, Riser Interference

[26] DNV-RP-F204, Riser Fatigue

[27] DNV-RP-F206, Riser Integrity Management

[28] NACE MR0175 5/ISO 15156-1, Petroleum, Petrochemical, and Natural Gas Industries—Materials for Use in

H2S-containing Environments in Oil and Gas Production—Part 1: General Principles for Selection of

Cracking-resistant Materials

[29] NACE SP0108, Corrosion Control of Offshore Structures by Protective Coatings

[30] NACE Technical Committee Report 21413, Prediction of Environmental Aggressiveness in Oilfield Systems

from System Conditions, 2017

5 NACE International, 15835 Park Ten Place, Houston, Texas, 77084, www.nace.org.


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