Integrity Management Plan for Pipeline-G03178 Idzuari Azli

2016

Kamilan, Idzuari Azli

MSc Asset Management & Maintenance

1/2/2016

Integrity Management Plan for [Pipeline Operating Company]

Integrity Management Plan for [Pipeline Operating Company] 2016

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Table of Contents 1.0 OBJECTIVE .......................................................................................................................................... 3

2.0 Scope ................................................................................................................................................. 4

2.1 Flowline & Pipeline Limits ............................................................................................................. 5

3.0 ORGANIZATION & RESOURCES .......................................................................................................... 7

3.1 Organizational Structure ............................................................................................................... 7

3.2 ROLES AND RESPONSIBILITIES ....................................................................................................... 7

Maintenance & Integrity Manager .................................................................................................. 7

Pipeline TA ....................................................................................................................................... 8

RBI engineer / AIM contractor ........................................................................................................ 9

Process TA ....................................................................................................................................... 9

Certification Engineer ...................................................................................................................... 9

Operations Manager ....................................................................................................................... 9

4.0 HAZARD IDENTIFICATION & MANAGEMENT ................................................................................... 10

4.1 Pipeline Design & Compliance ..................................................................................................... 10

4.2 Safety Management System ........................................................................................................ 10

4.3 Safety Critical Elements (SCE) ...................................................................................................... 10

4.4 Performance Standards ............................................................................................................... 10

4.5 Safety Critical Equipment ............................................................................................................ 11

4.6 Pipeline RBI .................................................................................................................................. 12

5.0 PIPELINE MAINTENANCE, INSPECTION, TEST AND REPAIR STRATEGIES (MITRS) ........................... 13

5.1 GENERIC MAINTENANCE STRATEGIES ......................................................................................... 14

Equipment Boundary ..................................................................................................................... 15

Standards ....................................................................................................................................... 15

Failure Mode and Effect Analysis .................................................................................................. 15

Maintenance / Inspection Regime ................................................................................................ 15

Preventative / Predictive Maintenance......................................................................................... 15

5.2 Flow Assurance ............................................................................................................................ 16

5.3 In-Line Inspection / Pigging ......................................................................................................... 16

5.4 MITRS Planning ............................................................................................................................ 16

5.5 Extent of Inspection..................................................................................................................... 17

5.6 Detail Procedure for Inspection .................................................................................................. 17

5.7 Inspection Results and Assessment............................................................................................. 17

6.0 EMERGENCY RESPONSE .................................................................................................................. 18


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6.1 Pipeline Defect Assessment Manual (PDAM) .............................................................................. 18

Introduction ................................................................................................................................... 18

Scope & Method ............................................................................................................................ 18

Defect Applicability for Fitness-for-Purpose Assessment ............................................................. 18

Suitability of Fitness-for-Purpose Assessment .............................................................................. 19

6.2 Deferral of Inspection .................................................................................................................. 20

7.0 PERFORMANCE ASSESSMENT / ASSURANCE .................................................................................. 21

7.1 Independent Verification ............................................................................................................ 21

7.2 Annual Integrity Review .............................................................................................................. 21

7.3 Key Performance Measures ........................................................................................................ 21


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1.0 OBJECTIVE

The purpose of the Pipeline Integrity Management Plan is to define the means by which the integrity of the pipeline static pressure systems is assured through defined inspection plans schedules and relevant monitoring and mitigation measures. This includes definition of the program and activities, organization including roles and responsibilities, safety critical system and its performance standards, and data and information management. Pipeline Integrity Management Plan is developed as an integral part of [PIPELINE OPERATING COMPANY] Integrity Management Scheme (IMS) to achieve compliance with corporate goals of no accidents, no harm to people, and no damage to the environment also compliance with [COUNTRY] statutory regulations. The position of this document within the overall [PIPELINE OPERATING COMPANY] Integrity Management Scheme is shown in Figure below. Pipeline Integrity Management is defined as the application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids throughout the life cycle of a pipeline; the focus for pipeline integrity is to define the minimum functional and performance oriented requirements and guidelines for pipeline design, planning and execution of pipeline operations in [PIPELINE OPERATING COMPANY].

Figure 1.1 Facilities Integrity Management System Overview


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2.0 Scope

The assigned assets included in the scope of Pipeline Integrity management Scheme is shown in Figure 2-1. The design life of the infield Flow lines is 10yrs and the GEP is 25 years

Table 2.1 [PIPELINE OPERATING COMPANY] Pipeline & umbilical mechanical details Line ID Description Contents Leng

th

Comment

P1 10” #1500, Production Flowline, API 5L X52

SMLS, wt 22.2mm.

Oil, Gas & Water 2.2km Insulated pipe, 24mm 3

LPP. No concrete

P2 10” #1500 Production Flowline, API 5L X52

SMLS, wt 22.2mm.

Oil, Gas & Water 2.2km Insulated pipe, 24mm 3

LPP. No concrete

P4 8” #2500, Water Injection Flowline API 5L X52

SMLS, wt 18.3mm

Injection Water 2.2km Coating 3.0mm 3LPE.

Carrier pipe for the 4” Gas

Lift flowline.

P3 4” #1500, Gas Lift Flowline, API 5L X52 SMLS,

wt 7.9mm

Dry Gas 2.2km Coating 3.0mm 3LPE.

Piggy backed onto the 8”

WI flowline.

Umb 1 Power & Chemical Injection

Umbilical.

OD 5.25” (133.7mm) Static Section.

OD 6.0” (153.3mm) Dynamic Sect.

Production

Chemicals &

Electrical Power

2.2km Internal Nylon Hoses used

for transporting chemicals.

GEP 10” #1500, Production Flowline, API 5L X65

ERW, wt 12.7mm.

Dry Gas 95.6k

m

Coating 5.5mm AE &

30mm Concrete.

P5 10” #1500, Production Flowline, API 5L X65

ERW, wt 15.9mm. The line has 7 buckle triggers

installed; each buckle trigger has 120m of heavy

wall pipe, wt 18.3mm.

Oil, Gas & Water 17km Insulated pipe, 30mm PUF

+ 5.0mm HDPE + 30mm

CWC.

P6 10” Pigging/Gas Lift, API 5L X65 ERW, wt

15.9mm.

Injection water or

gas as and when

needed.

17km Non Insulated pipe, 2.5mm

3LPE + 30mm CWC.

Umb 2 6” Power, Hydraulic & Chemical Injection

Umbilical

Production

Chemicals,

electrical power

and Hydraulic

Fluid.

17km

Table 2.2 Operating parameters

Line ID P1 - 10” P2 - 10” P4 – 8” P3 – 4” P5 - 10” P6 - 10” GEP

Service Production Production Water Inj Gas Lift Production Pigging (Water) or Gas

Lift

Dry Gas

Operating Press

13.5barg (top of Riser)


254barg (at PLEM 2)

190barg (top of Riser)



190barg (top of Riser)

Operating

Temp

30°C - 80°C 30°C - 80°C 30°C - 50°C 30°C - 50°C 30°C – 80°C 30°C – 80°C 30°C - 50°C

Design Pressure

228barg 228barg 222barg 222barg 228barg 228barg 222barg

Design Temp 130°C 130°C 60°C 90°C 130°C 130°C 90°C

Hydrotest

Press

262barg 262barg 356.5barg 255.3barg 262barg 262barg 255.3barg

Piggable Yes Yes No* No** Yes**** Yes**** No***

Flexible Riser 10” 10” 10” 4” 10” 10” 10”

Volume 90m3 90m3 58m3 16.8m3 728m3 728m3 4,604M3


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Table 2.3 - Comments on Piggability Note Comments

* The Water Injection Flow Line is dual diameter 10”/8”. There are no permanent pig traps fitted

on the FPSO or the WHP. Also space for temporary traps on the WHP is very limited making

pigging extremely difficult even if pigs can be launched from the FPSO.

** The Gas Lift Flow Line is not piggable due to reduced bore Tee’s installed in the FPSO topside.

Also there are no permanent pig traps fitted on the FPSO or WHP.

*** The GEP is technically piggable but has no permanent pig traps fitted. A temporary topside and

subsea trap would be required along with a DSV and divers to install it. Any pigs used must be

sized to bridge the body cavity of the inline check valve in PLEM 1.

**** The Dua flowlines are designed for round trip pigging. Both lines have features in PLEM 3 that

require the use of special designed pigs. The Pigging line contains an inline check valve and the

Production flowline contains a Wye. Only the three module articulated pigs especially designed

for the Dua system should be used during operational round trip pigging. The use of standard

size single module pigs is not permitted for normal operational pigging.

2.1 Flowline & Pipeline Limits

The limits of the Chim Sao Flow lines, Pipeline and Umbilical are presented below:- • The Chim Sao 10” Production Infield Flowline (P1) – The flowline extends approx. 2.2km from the hang off flange in the FPSO turret to the flange at the top of the riser on the WHP. This includes the 10” flexible riser from the FPSO to PLEM 2 which is located on the seabed 250m from the FPSO turret. • The Chim Sao 10” Production Infield Flowline (P2) – The flowline extends approx. 2.2km from the hang off flange in the FPSO turret to the flange at the top of the riser on the WHP. This includes the 10” flexible riser from the FPSO to PLEM 2 which is located on the seabed 250m from the FPSO turret. • The Chim Sao 8” Infield Water Injection Flowline (P4) – The flowline extends approx. 2.2km from the hang off flange in the FPSO turret to the riser top flange on the Well head platform. Note:- This line acts as the carrier for the 4” Gas Lift Line which is piggybacked on top of it. This includes the 10” flexible riser from the FPSO to PLEM 2 which is located on the seabed 250m from the FPSO turret. • The Chim Sao 4” Infield Gas Llift Flowline (P3) – The flowline extends approx. 2.2km from the hang off flange in the FPSO turret to the flange at the top of the riser on the WellHead Platform. Note:- This flowline is piggy backed on top of the 8” WI Flowline P4. This includes the 4” flexible riser from the FPSO to PLEM 2 which is located on the seabed 250m from the FPSO turret. • The Chim Sao 10” Gas Export Pipeline – The GEP extends approx. 95.6km from the hang off flange in the FPSO turret to the upstream flange of valve P4V11 in the 10” crossover line within PLEM 4 at the tie-in to the NCSP Pipeline at KP75. This includes the 10” flexible riser from the FPSO to PLEM 1 which is located on the seabed 250m from the FPSO turret. • The Chim Sao 6” Electrical Power and Chemical Injection Umbilical – The umbilical extends from the FPSO to the Well head platform approx. 2.2km away. • The Dua 10” Production Flowline (P5) – The flowline extends 17km from the hang off flange in the FPSO turret to the TPAM. Note this flowline has 7 buckle triggers installed roughly equidistant along it’s length to mitigate against uncontrolled lateral buckling. This includes the 10” flexible riser from the FPSO to PLEM 3 which is located on the seabed 250m from the FPSO turret. • The Dua 10” Pigging and Gas Lift Flowline (P6) – The flowline extends 17km from the hang off flange in the FPSO turret to the TPAM. This flowline is required to provide a round trip pigging capability for pigging and wax removal of the of the production flowline and gas lift


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capability as and when gas lift is required. This includes the 10” flexible riser from the FPSO to PLEM 3 which is located on the seabed 250m from the FPSO turret. • The Dua 5.5” Power, Hydraulic, and Chemical injection umbilical – The umbilical extends 17.5km from the hang off flange below the FPSO turret to the TPAM. The umbilical is routed between the flow lines to provide a degree of protection from fishing boat activities.

Figure 2.1 [PIPELINE OPERATING COMPANY] Pipeline Assets Diagram

DUA

TPAM

DUA

MWPGB

CHIM SAO & DUA FIELD LAYOUT

10" G

as E

xpor

t 95.

6km

Shuttle

Tanker

Chim Sao

(FPSO)

KNOC

TIS

BP

Lan Tay

KNOC

Rong Doi

NCS GEP

(Wye) KP 75

Dinh Co

Terminal

10" Pigging/Gas Lift l

ine17.05km

10" Production lin

e17.05km

PLEM 3

DUA

(Future)

Umbilical

Chim Sao

(WHP)

PLEM 2

PLEM 1

(Gas Export)

Infield Flowlin

es 2.2km

POVO

TIM

Umbilical

CHIM SAO - INFIELD FLOWLINES

1 off 4" Gas Lift

1 off 8" Water Injection

2 off 10" Production

1 off Power & Chemical Umbilical

DUA - INFIELD FLOWLINES

1 off 10" Pigging Line – Water/Gas Lift Service

1 off 10" Production Line

1 off Power, Chemical & Control Umbilical

CHIM SAO – GAS EXPORT PIPELINE

1 off 10" Gas Export to PLEM 4

Bien Dong

Bien Dong

TIS


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3.0 ORGANIZATION & RESOURCES

3.1 Organizational Structure

The key personnel accountable for the delivery of the [PIPELINE OPERATING COMPANY] Pipeline Integrity Management Scheme are detailed in the following sections.

3.2 ROLES AND RESPONSIBILITIES

Maintenance & Integrity Manager

Responsible and accountable to:

[1] Develop, implement and assure that policies and procedures for the safe and efficient

maintenance of offshore plant and equipment are in place and in compliance with the

relevant standards.

[2] Plan and coordinate the activities of external contractor specialists and vendors in

relation to engineering and maintenance activities.

[3] Ensure that the facilities are operated and maintained in accordance with [PIPELINE

OPERATING COMPANY], National and International Standards including the

company’s HSEQ system.

[4] Provide a technical support service to the operations team by ensuring that all

[PIPELINE OPERATING COMPANY] assets are developed, operated safely and cost

effectively to meet operational and business targets.

[5] Ensure career development of existing and recruitment of new staff in accordance

with agreed headcount budgets and business needs. Ensure development of National

staff into progressively more senior positions within the organization.

[6] Ensure that the process equipment, power generation, compression and utilities

systems are maintained safely, efficiently and with minimal environmental impact in

accordance with current legislation, the [PIPELINE OPERATING COMPANY]

Management System and the Life Cycle Plan.

[7] Ensure that the maintenance policy is implemented in accordance with the [PIPELINE

OPERATING COMPANY] Business Plan and to contribute to the development of a

maintenance plan appropriate to the field facilities.

[8] Supervise the Maintenance workforce. To develop and maintain a flexible and

effective work culture where all employees and contractors strive to achieve the pre-

set [PIPELINE OPERATING COMPANY] business goals.

[9] Assist in establishing and ranking risks involved in maintenance activities, and

suggesting ways to mitigate such risks.


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Pipeline TA

Has ownership of Pipeline Integrity Management Scheme across PIMS and is responsible &

accountable to:

[1] Act as SPA / owner of the Pipeline Integrity Management Plan and ensure that the

scheme is being complied with.

[2] Act as SPA for the Safety Critical Element / Performance Standards (SCE / PS) within

discipline area and is identified within the PIMS scheme and verify annually that it is

functioning as per the system performance standard.

[3] Carry out annual integrity reviews as defined in PIMS scheme and report findings to

management.

[4] Ensure relevant [PIPELINE OPERATING COMPANY] SOP’s, Premier Codes,

Standards and Specifications, are complied with within discipline area.

[5] Ensure that the technical content of changes undertaken via the [PIPELINE

OPERATING COMPANY] MOC process is in compliance with Premier Standards and

Codes, and Vietnam regulatory requirements.

[6] Ensure changes and updates to SOP’s, Standards and Specifications, are periodically

assessed and when appropriate incorporated into the PIMS.

[7] Ensure deviations from Premier codes and standards are identified, technically

assessed and authorized in accordance with [PIPELINE OPERATING COMPANY]

eMOC/TQ processes.

[8] Endorse results of fitness for service and RBI assessments on plant and equipment

within discipline area.

[9] Review and approve changes / additions to maintenance / inspection routines and

frequencies via the Maintenance eMOC process.

[10] Review and approve the deferral of Safety Critical maintenance / inspection via the

maintenance eMOC process.

[11] Provide adequate and timely information on equipment due for inspection and testing

to facilitate scheduling, planning and execution of the work.

[12] Review and approve technical changes to Site Operating Procedures (SOP’s) as

required.

[13] Approve the technical content of material requisitions as required via the procurement

process and procedures.

[14] Inform Integrity manager of significant risk exposure identified by inspection and

testing

[15] Ensure inspection data held within the mechanical integrity database and allow

inspection progress report to be provided / monitored.

[16] Schedule and execute Inspection, Test and Repair Strategies (ITRS) at required

inspection intervals detailed in the [PIPELINE OPERATING COMPANY] pipeline

system RBI.

[17] Collate and review associated condition assessments and anomaly data to facilitate

the evaluation of facilities integrity.

[18] Review and/or submit requests for the deferment of PMR or non-routine work in

accordance with Premiers Maintenance Deferral process.


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RBI engineer / AIM contractor


[1] Develop and maintain inspection strategies.

[2] Implement all inspection activities as per PMR routines, in an effective manner.

[3] Report equipment condition and maintenance of PMR inspection routines.

[4] Develop detailed inspection work packages.

[5] Generate inspection findings, upload inspection data to [PIPELINE RBI SOFTWARE],

reporting and recommendations and ensures that equipment is maintained fit for

purpose.

[6] Conduct inspection campaigns as required.

[7] Input data and maintain the integrity database as required.

[8] Manage baseline data and control.

[9] Liaise with [PIPELINE OPERATING COMPANY] documentation control as required.

Process TA


[1] Act as the custodian of the corrosion control matrices.

[2] Perform periodic review of the corrosion control matrices (including both CP and

process fluids)

[3] Monitor & report on corrosion performance indicators (including both CP and process

fluids)

[4] Organize corrosion awareness instruction / meetings.

[5] Compile & issue corrosion reports.

[6] Perform corrosion data analysis (historical & current/inspection & process), including

trending, prediction & reporting.

[7] Ensure all corrosion condition data required to make informed decisions is available.

[8] Provide technical support to the Static Plant TA for Integrity Reviews and Fitness for

Service assessments.

[9] Provide support for Flow Assurance reviews on pipeline and process plant.

Certification Engineer


[1] Ensure that all [PIPELINE OPERATING COMPANY] facilities are in compliance with

[COUNTRY] regulations.

[2] Maintain database of all regulatory certification and expiry dates.

[3] Manages the process for the proactive recertification of equipment as required by the

regulatory bodies.

Operations Manager


[1] Operate the rotating equipment within its design envelope and in conformance with

documented procedures.

[2] Maintain and auditing key procedures.

[3] Carry out routine surveillance and watch keeping.


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[4] Recognize abnormalities or excursions and responding accordingly.

[5] Manage operational overrides.

4.0 HAZARD IDENTIFICATION &

MANAGEMENT

4.1 Pipeline Design & Compliance

The offshore pipelines are designed in accordance with DNV OS-F101 and the onshore sections are designed in accordance with ASME B31.8. The RBI methodology used to determine the IMR program complies with both codes. This philosophy determines the inspections and monitoring required to ensure safe and reliable operation of the pipeline system, and all inspection and monitoring requirements identified during the design phase as affecting safety and reliability during operation are to be covered. DNV OS-F101 also requires a long term inspection program reflecting the overall safety objective for the pipeline to be established and maintained / updated on a regular basis.

4.2 Safety Management System

Within the 500 m zone of all [PIPELINE OPERATING COMPANY] installations the credible Major Accident Events (MAE) and events have been assessed for the pipeline and risers as part of the safety management system. Safety Critical Elements (SCE) have been identified to mitigate or prevent these MAE’s

4.3 Safety Critical Elements (SCE)

Safety Critical Elements have been identified from Hazard Identification (HAZID) study to prevent, detect, mitigate, and control Major Hazards. The Safety Critical Elements related to this document are shown in Table 5.1.

4.4 Performance Standards

Performance Standards have been developed for Safety Critical Systems, specifying performance required for the SCS, including functionality, reliability, and availability. The performance standards relating to PIMS are listed in Table .1.


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Table 5.1 MAE, SCE & PS

Facility SCE

Function SCE ID

SC System / Equipment

Major Accident Hazard

Block 12W Prevention PS-04 Turret & mooring system

Riser system is located within the turret of the FPSO and associated hazards will most likely affect the SCE.

Block 12W Prevention PS-05 Pipelines and Risers

Process Containment

Block 12W Prevention PS-08 Ignition prevention Ignition from equipment (electrical & non-electrical) riser area

Block 12W Prevention PS-13 Lifting Appliances

Lifting facilities and its associated activities shall avoid the riser areas to reduce risks from dropped objects and mechanical impacts

Block 12W Prevention PS-16 Well Hydrocarbon Containment

Hydrocarbon Containment

Detection DS-01 Fire and Gas Detection/ Alarm

Fire and Gas system shall, depending on the ESD Cause and Effect Chart, result in the initiation of ESD system

Isolation CS-01 ESD ESDVs are installed on the risers system to isolate the well fluids.

Protection MS-05 Passive Fire and Blast Protection

PFP shall ensure that the riser system components have adequate fire resistance to reduce consequences of fire as far as practicable.

4.5 Safety Critical Equipment

SCE equipment is defined as plant and equipment where failure in service could result or contribute to major accident / process safety event (MAE). The following equipment has been identified as being safety critical (SCE) and the individual equipment has been identified in the Performance standard as SCE. For the pipelines and risers the generic safety critical equipment is listed as follows.

Pipeline and riser

Buckle triggers, TPAM and PLEM manifolds

SSCV

Pig Traps and associated process piping.

Isolation ESDVs


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4.6 Pipeline RBI

[PIPELINE OPERATING COMPANY] applies a Risk Based Inspection (RBI) approach for determining inspection scope and intervals for the pipeline infrastructure. The method and results of the initial RBI study are described in “Subsea pipelines risk based inspection plan”.

The RBI document describes how risks pertaining to the pipelines have been assessed and the

inspection activities chosen to mitigate the identified risks. The inspection tasks and frequencies in the

RBI report and subsequently implemented in [PIPELINE RBI SOFTWARE] are however only initial

activities and frequencies. During operation inspection results and other operational information

relevant to the integrity of the pipeline needs to be evaluated and risks re assessed, something which

may result in a need to update the inspection program as described in the flowchart below.

Figure 4.1: Pipeline integrity Management process

Identify Potential

Pipeline Impact to

HCAs

Initial Data Gathering,

Review, and

Integration

Initial Risk

Assessment

Develop Baseline Plan

Perform Inspection

and/or Mitigation

Revise Inspection

Mitigation

Plan

Reassess

Risk

Update, Integrate,

and Review Data

Manage Change

Evaluate

Program


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5.0 PIPELINE MAINTENANCE,

INSPECTION, TEST AND REPAIR

STRATEGIES (MITRS)

In [PIPELINE OPERATING COMPANY] the subsea pipeline programme is undertaken in conjunction

with the structural subsea inspection. The pipeline risers are included in the structural inspection

workscope.

Subsea inspection of pipelines is mainly driven from the subsea RBI program.

In addition opportunities are taken to share vessels with other operators in the vicinity such as

Rosneft, KNOC, BDPOC and NCSP when circumstances allow this.

The frequency and scope of the pipeline inspection and repair is driven by the following:

a) Previous inspection results.

b) Criticality of the pipeline in term of Major Accident Event risk and commercial loss.

c) Potential operating events e.g. dropped objects, exclusion zone encroachment.

The subsea inspection programme is scheduled in the maintenance management system in order for

the activity to be included in the Integrated Field Plan.

[PIPELINE OPERATING COMPANY] MITRS management cycle overview is shown in Figure 5.1, it

illustrate the importance of continued cycle of updating maintenance, inspection, testing & repair

strategy, following the implementation, changes analysis and remedial work performed.

Figure 5.1 [PIPELINE OPERATING COMPANY] MITRS Management Cycle


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5.1 GENERIC MAINTENANCE STRATEGIES

The Generic Maintenance Strategies are a means of defining the maintenance and inspection regimes

appropriate to equipment types, and take account of the equipment degradation mechanisms, rates

and consequences of failure. A set of Generic Maintenance Strategies covering the majority of

equipment types has been developed for [PIPELINE OPERATING COMPANY].

Figure 5.2 [PIPELINE OPERATING COMPANY] Generic Maintenance Strategy Development

Table shows the GMSs that have been developed for [PIPELINE OPERATING COMPANY]

PIMS and underpin the maintenance of pipeline integrity and reliability. Note that specific

pipeline equipment is covered by other IM Schemes. These are detailed in the table below.

Table 5.1 [PIPELINE OPERATING COMPANY] Generic Maintenance Strategies

Equipment GMS No. IM Schemes

Pipelines PIMS 200

Flexible Risers F03 PIMS 200

PLEM PIMS 200

Umbilicals PIMS 200

Pipeline riser M16 PIMS 200

PMR’S

JDE CMMSMaisy


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Equipment Boundary

This defines the equipment, components and accessories which are included in the strategy

and what is not. The equipment types included in the strategy are identified by their

maintenance failure / equipment failure class.

Standards

This section identifies all standards which may affect the function of the equipment, the levels

of performance which the equipment must attain, or may specify particular maintenance

requirements. This includes any PSs, national or international standards and [PIPELINE

OPERATING COMPANY] requirements

Failure Mode and Effect Analysis

The FMEA is the section which provides the detailed technical justification behind the

maintenance task selection, and also does the following:

Defines the function of the equipment – taking account of any functional or

performance requirements of the standards.

Identifies how the equipment may fail to perform that function

The specific modes of failure of the equipment.

Assigns maintenance tasks where these can prevent or detect the failure modes.

Maintenance / Inspection Regime

This final section groups the maintenance tasks from the FMEAs into a set of Planned

Maintenance Routines (PMRs) for the equipment. Frequencies are assigned to the routines

and technical justification is provided for the selected frequencies. Where possible, this is

based on actual or industry standard equipment failure data, or when this data is not available,

on known good practice.

Generic PMRs have been written to accompany each GMS. As the maintenance strategies

are implemented in the assets, the PMRs are customized to take account of any asset-specific

issues. A record is made of any asset-specific differences to the generic strategy (e.g. PMR

content or task frequency), including technical justification for the differences.

Preventative / Predictive Maintenance

The implementation of the equipment total care programme is through the following:

PMRs (including inspection) are assigned and scheduled in MAISY.

Frequent checks of a basic care nature are carried out as described in (e.g. service

books, checklists, etc.).

Predictive and condition monitoring is carried out following the regime defined in the

maintenance strategy.

Contractual arrangements with selected vendors.


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5.2 Flow Assurance

The internal condition of the pipelines is assessed monthly to verify the following: Pipeline is operated within its design envelope

Fluid chemistry has not significantly changed from FEED / PFD assumptions.

ER Probe, Corrosion Coupon and UT wall thickness results are within design assumptions.

Chemical treatment is being carried out as per operational requirements.

To facilitate the above chemical and corrosion control matrices have been developed for each of the facilities. These identify test, sampling and inspection frequencies, and the acceptance criteria for each of the parameters monitored. The matrices are owned by the production chemist and are reviewed every 6 months. The management of the chemical and corrosion control matrices provide an important input into the overall RBI process and helps drive key decisions in the development of the pipeline internal inspection program this included the decision to deploy inline inspection tools and/or pigging programmes. Details of the corrosion and chemical controls matrices can be located in the Pressure Systems Integrity Management Scheme Ref PSIMS 100 Appendix 3 Flow Assurance Management is achieved by:

Identifying, understanding and mitigating against, where practicable, the threats to the

pipelines from non optimum flow condition.

Defining the operating envelope for the pipelines regarding corrosion control and product

quality.

Regular review and assessment of the process fluids.

Regular review of the process parameters, flowrate and properties to assess their impact on

the corrosion strategy.

Hydrate management.

5.3 In-Line Inspection / Pigging

Refer to Subsea pipelines RBI plan for ILI requirements.

5.4 MITRS Planning

Periodic inspection of static equipment, is planned and scheduled through Planned Maintenance Routines (PMRs), managed within the MAISY Computerized Maintenance Management System (CMMS). The detail of In-Service Inspection Process Planning is attached in Appendix 5.


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5.5 Extent of Inspection

The inspection techniques are specified based on the anticipated modes of damage / degradation mechanism identified by the RBI process and should be the most appropriate techniques in terms of reliability, detect ability, and cost effectiveness.

5.6 Detail Procedure for Inspection

Detailed procedures and method statements have been developed for all anticipated failure modes are detailed as shown in Table 6.25.2.

Table 6.2 Subsea Inspection Procedures

Document No. Description

MNT 426 Underwater Inspection General

MNT 420-04 Underwater Inspection Video Recording

MNT 420-11 Underwater Inspection Cleaning

MNT 420-03 Underwater Inspection Marine Growth Survey

MNT 425-11 Underwater Inspection CP Measurements

MNT 420-07 Underwater Inspection Replica Moulding

TBA Underwater Inspection EMD/ACFM Crack Detection

5.7 Inspection Results and Assessment

Inspection reports should be reviewed by the Senior Asset Integrity Engineer to compare with acceptance criteria for relevant equipment types, establish the deterioration rates, assess remaining life, and define remedial action necessary to ensure fit for service condition over define period of operation. Some in-service damage mechanisms such as general corrosion or erosion progress in a sufficiently linear manner to allow reliable calculation of deterioration rates. [PIPELINE RBI SOFTWARE] is used to set threshold and alarm level, determine remaining life and future inspection interval so that the loss of thickness remains within the allowable limits of the design code. [PIPELINE RBI SOFTWARE] automatically generates anomalies where a particular threshold has been crossed. Reporting requirements for non-conformances or integrity threats are detailed together with the control and warning limits and the responsible parties (recording, reporting and action parties) in the Anomaly Assessment Procedure.


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6.0 EMERGENCY RESPONSE

6.1 Pipeline Defect Assessment Manual (PDAM)

Introduction

Pipeline Defect Assessment Manual contains guidance on the assessment of a wide variety of

different types of defect, under various loading conditions, that may be found in a pipeline.

Scope & Method

The scope of the Pipeline Defect Assessment Manual encompasses steel line pipe

manufactured to API 5L, EN10208-2: Part 2, ISO 3162: Part 2 1996, DNV OS F-101, EEMUA

Pub No. 166, or equivalent.

The assessment methods given in the Pipeline Defect Assessment Manual are for defects in

onshore and offshore transmission pipelines designed to an internationally recognized pipeline

design code.

The assessment methods presented in the manual are the ‘best’ methods for assessing the

particular type of damage. The ‘best’ method has been primarily selected on the basis of the

quality of the fit of the predictions to full scale test results, although ease of use and range of

applicability have also been considered.

Methods do not exist to assess some types of damage that may be found in a pipeline, under

certain loading conditions. Furthermore, it is not possible to identify all combinations of defect

and loading in a particular situation.

For more information on a particular assessment method, or alternative methods that may be

available, please refer to Ref. Pipeline Defect Assessment Manual

Defect Applicability for Fitness-for-Purpose Assessment

The summary of guidance for the assessment of the following types of defect in PDAM, is

listed in the table below;


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Table 6.1 Summary of Assessment Methods by Defect Type and Loading

Damage Mechanism

Inte

rna

l P

ressure

(Sta

tic)

Inte

rna

l P

ressure

(Cyclic

)

Exte

rna

l P

ressure

Axia

l F

orc

e

Ben

din

g M

om

ent

Com

bin

ed L

oad

ing

Defect-free pipe Yes Yes Yes Yes Yes Yes

Corrosion Yes Yes No Yes Yes Yes

Gouges Yes Yes No Yes Yes Yes

Plain dents Yes Yes No No No No

Kinked Dents No No No No No No

Smooth dents on welds No Yes No No No No

Smooth dents and gouges Yes Yes No No No No

Smooth dents and other types of defect Yes Yes No No No No

Manufacturing defects in the pipe body Yes Yes No Yes Yes Yes

Girth weld defects Yes Yes No Yes Yes Yes

Seam weld defects Yes Yes No Yes Yes Yes

Cracking Yes Yes No Yes Yes Yes

Environmental Cracking Yes Yes No Yes Yes Yes

Notes:

Denotes cases where specialist assistance is required

Denotes cases where specialist assistance may be required

Suitability of Fitness-for-Purpose Assessment

Before undertaking any fitness-for-purpose assessment of a pipeline containing a defect, the

need for undertaking the assessment should be questioned. The following is a list of general

questions that provide guidance regarding the type of issues that should be addressed

Appraisal

[1] Is it really a defect, can we readily dismiss it as a defect

Is the defect really a defect, or is it some feature of the inspection method

(e.g. a low level anomaly reported during pigging.

Is the defect within design and fabrication acceptance levels?

What is industry experience of similar defects?

[2] Is it a defect?

Do we know how the defect was formed, and how it may develop in the

future?

Is the defect indicative of poor practice during construction or operation, and

as such can be controlled by other methods?

[3] Who is competent to assess the defect?


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What are the legal implications (e.g. professional liability), what are the views

of the regulatory body, and who would be responsible for the structure, and

any defect assessment relating to it?

Are the current staffs capable and experienced in applying fitness-for-purpose

methods?

[4] Is it worth the effort?

Is it cheaper to repair than to assess?

Assessment

[1] Can fitness-for-purpose methods provide an answer?

Can fitness-for-purpose methods solve the problem? For example, are the

methods robust for the particular defect, geometry and loading?

What test data exists, and how reliable is it? If the test data is sparse, what

confidence is there in any engineering judgement, or are special tests

required?

Safety Factors and Probabilistic Aspects

[1] What safety margins should be used?

If fitness-for-purpose methods are applied, what safety factors should be

used?

How should the safety factors be defined?

Consequence

[1] What are the consequences of getting it wrong?

Is a risk analysis required?

6.2 Deferral of Inspection

Request for deferral of scheduled inspections and tests shall be assessed and approved or

rejected by the Technical Authority (TA) through the eMOC process to provide assurance that

integrity is not compromised.

An appropriate risk assessment should be performed, the results of which should be agreed

with the TA. Review should document the impact of the change, if any, on the original

inspection and test plan and any mitigating actions required. The level of risk assessment may

range from a very simple review completed by the inspection engineer up to more detailed

multi-disciplinary team review process. The risk assessment for reviewing the deferral of major

or multiple equipment items should adopt a multi-disciplinary approach.

When required by the TA, Consent to Operate (CTO) can be raised and endorsed by

management to allow continued operation (Ref. Case to Operate, document number (hold))


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7.0 PERFORMANCE ASSESSMENT /

ASSURANCE

The integrity programme is periodically reviewed to ensure the equipment is fit for purpose and that the appropriate corrective measures are identified and implemented. Key elements of the review are assurance of conformity with the programme objectives, review of relevant KPIs and checking that the applicable performance standards are being met.

7.1 Independent Verification

[PIPELINE OPERATING COMPANY] adopts the principles of the UK Safety Case regulations with respect to independent verification of the performance and suitability of Safety Critical Elements (SCE). The assigned Independent Verification Body (IVB) assures compliance with the installation Performance Standards (PSs) through the Written Scheme of Verification (WSV). The Independent Verification Process is managed by the HSE Department with any anomalies reported by the IVB prioritized and tracked via the CARS action tracking system and/or the maintenance management system.

7.2 Annual Integrity Review

Annual integrity review are carried out against each Integrity Management Scheme (IMS) by the scheme responsible Technical Authority. The reviews are carried out to set format with results reported to Senior Management. The reviews are carried out where practical before the budget review cycle in order that any potential activity resulting from the review can be budgeted for.

7.3 Key Performance Measures

Key Performance Indicators (KPIs) have been developed to monitor performance and compliance against each scheme. With reference to the FIMS document (Ref. document number FIMS/000, section 8.3.1 to 8.3.2), Performance Managements KPIs are in place to monitor key systems and processes relating to Process Safety, Maintenance and Facilities Integrity. KPI’s have been developed to monitor the performance of each scheme. For this scheme the KPs form part of the Annual Integrity statement in Appendix 2.

Integrity Management Plan for Pipeline-G03178 Idzuari Azli

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