SP1210 Pipeline Operation and Maint

Petroleum Development Oman L.L.C.

UNRESTRICTED Document ID : SP-1210December 2003 Filing key :

Pipeline Operations and Maintenance

Keywords: Pipelines, Operations, Maintenance, Integrity.

This document is the property of Petroleum Development Oman, LLC. Neither the whole nor any part of this document may be disclosed to others or reproduced, stored in a retrieval system, or transmitted in any form by any means (electronic, mechanical, reprographic recording or otherwise) without prior written consent of the owner.

Pipeline Operations and Maintenance Version 2.0

Authorised For Issue

Signed :........................................................Naaman Naamani, UOX CFDH Technical & Operational Excellence

The following is a brief summary of the 4 most recent revisions to this document. Details of all revisions prior to these are held on file by the issuing department.

Version No.

Date Author Scope / Remarks

Version 1.0 July 2003 UOM/6 Initial issue. Supersedes and replaces the ‘Operations and Maintenance’ content of ERD 10-01.

Version 1.1 December 2003 For commentingVersion 2.0 30 December

2003UEL1 / TTP55 Issue for Approval

December 2003 Page i SP-1210

Version 2.0 Pipeline Operations and Maintenance

Contents

1. Introduction...................................................................................................................... 11.1 Purpose....................................................................................................................... 11.2 Changes to the Specification.......................................................................................1

2. Specification for Pipeline Operations and Maintenance...............................................22.1 Scope.......................................................................................................................... 22.2 Pipeline Classification.................................................................................................22.3 Risk Management.......................................................................................................2

2.3.1 General.......................................................................................................22.3.2 Risk Identification.......................................................................................22.3.3 Risk Assessment.........................................................................................32.3.4 Risk Control................................................................................................32.3.5 Risk Recovery.............................................................................................4

2.4 Pipeline Integrity Activities.........................................................................................42.4.1 Commissioning and Handover.....................................................................42.4.2 Operations...................................................................................................42.4.3 Maintenance...............................................................................................52.4.4 Inspection Activities...................................................................................72.4.5 Defects Assessment And Remedial Actions.................................................9

2.5 Emergency Response................................................................................................112.6 Performance Review And Abandonment...................................................................122.7 Documentation and Information Systems..................................................................13

2.7.1 Plans......................................................................................................... 132.7.2 Information Systems.................................................................................13

2.8 Control Framework...................................................................................................142.9 Effective Period........................................................................................................ 142.10 Review and Improvement...............................................................................14

Appendix A - Glossary of Terms, Definitions and Abbreviations....................................15A.1 Terms and Definitions....................................................................................15A.2 Abbreviations......................................................................................................16

Appendix B References.....................................................................................................17

Appendix C Failure Mode & Effect Analysis; Basis and Examples................................20

User Comment Form......................................................................................................... 23

SP-1210 Page ii December 2003


1. Introduction

1.1 Purpose

The main objective of this document is to specify the requirement for operations and maintenance of flowlines, headers, pipelines and pipeline accessories covering the operations, maintenance, inspection, and abandonment phases, to maintain pipeline interity.

The detailed requirements previously specified in ERD 10-01, which are dependent on the individual COPs, are similarly separated into two documents, SP-1211, Pipeline Engineering (DEP 31.40.00.10-PDO) covering the Development Phase and this document, covering Operations and Maintenance. The limited treatment in ERD 10-01 of integrity during the construction phase is already included within the scope of SP-1208, Pipeline Construction Specification (formerly PCS-01) and SP1247, Construction of Non-Metallic Pipelines. It is crucial to state that ERD 10-01 is obslete now and being superceded by this specification, SP-1211 and SP-1247.

This document specifies operations and maintenance requirements to maintain pipeline integrity, as a subset of asset integrity and surface flow assurance as set forewarth in PL-32, MS-1001, COP114, COP115 and COP117.

1.2 Changes to the Specification

This specification shall not be changed without approval from the Custodian, the Functional Discipline Head Technical & Operational Excellence (CFDH), UOX, who owns this specification. User’s comments on this document, if any, are to be filled in the User Comments Form included as the last page of this specification. Send the copy with your comments and personal details to DCS.

December 2003 Page 1 SP-1210


2. Specification for Pipeline Operations and Maintenance

2.1 Scope

This specification details the minimum requirements for the integrity of all PDO pipelines and flowlines in the operational phase. The scope includes risk management, integrity related activities through the ‘Operate & Maintain’ and ‘Abandonment’ phases and management documentation/control systems. Definitions and abbreviations are listed in Appendix A and details of referenced documents in Appendix B.

The scope of this specification extends only to pipeline and flowline systems (as defined in Appendix A.1).

2.2 Pipeline Classification

SP-1211 (Pipeline Engineering) classifies all PDO pipelines and flowlines into three ‘Criticality Classes’: Class 1 Class 2 Class 3

For details of the classification criteria and definition of fluids types, reference should be made to SP-1211.

2.3 Risk Management

2.3.1 General

There are various risk management processes and systems that may apply during the operational phase of the pipeline. These include:

Failure Mode & Effect Analysis as conducted during the design and operational phase as part of the Corrosion Management Plan, See an example in Appendix C.

Pipelines HSE Case which uses HEMP to demonstrate that the hazards at the pipeline assets have been systematically identified, see section 2.3.2, and that management systems are in place to effectively control the risks, see section 2.3.4.

Inspection planning and integrity assessment using the Pipe-RBA system. Emergency Response system.

2.3.2 Risk Identification

The main threats and causes of failure in PDO pipeline and flowline systems are:

Internal corrosion, resulting from the corrosivity of the transported fluid. The risk of attack is dependent on fluid composition, process conditions and pipe material.

External corrosion, due to the local environmental conditions (soil, atmospheric, undersea) surrounding the pipeline.

Impact damage. This will typically arise from contact of buried pipelines by excavation equipment, line damage beneath road crossings or vehicle collisions with above ground lines. It is also an important risk to the integrity of loading lines, both undersea or between SBM and tanker.

Abrasion. This is not a significant risk to buried pipelines, but must be considered for above-ground flowlines, where abrasion between line and support or between adjacent lines may occur, generally due to thermal cycling and/or mechanical vibration from periodic surge conditions.

Over-pressurisation, which may be a consequence of any of the foregoing threats but which may also arise independently as a result of a control system failure.

Blockage or flow restriction, which also constitutes a functional failure with a quantifiable economic consequence in non-delivery of the planned product throughput.

SP-1210 Page 2 December 2003


This may result from a variety of causes, including valve failure, stuck pig, severe slugging or an accumulation of internal deposits/debris.

Third party activities by unauthorised third party activities can only be controlled by regular Right of Way inspections and visual/camera monitoring of fenced areas. Aerial or satellite reconnaissance is technically feasible but, given the low threat of sabotage on pipelines in Oman, this not considered necessary.

Risks pertinent to the operational and abandonment phases shall be considered through the systematic reviews outlined in the following sections.

2.3.3 Risk Assessment

Risks related to pipeline corrosion may be assessed through corrosion prediction/analysis, monitoring and inspection. It should be recognised that corrosion may take a variety of forms, including general attack, localised pitting, grooving and stress corrosion cracking (SCC) and can have a profound influence on risk. For example, localised internal pitting of carbon steel crude oil or water lines will normally culminate in pinhole leakage and limited loss of containment. By contrast, grooving attack or SCC of a high pressure gas pipeline may lead to a catastrophic rupture of the line.

Risk assessments of all threats such as third party and others shall be included in integrity reviews conducted on operational lines.

2.3.4 Risk Control

Risks that have been identified and assessed as outlined above must then be controlled. Typical control measures that are applicable during the operational phase are listed as follows:

The risk for internal corrosion shall be controlled by corrosion mitigation measures such as inhibition, routine pigging or a change in the operating mode.

The risk of external corrosion should be controlled by regular condition monitoring and maintenance of the CP system.

The risk of corrosion and impact damage should be controlled by application of available technology such as Pipe-RBA, and careful inspection and measurement against established acceptance criteria (e.g. inspection of external coatings against current coating standards and the regular surveillance of pipeline windrows and ROWs against SP-1208/SP-1247 requirements), ensuring that appropriate actions are scheduled for repair.

The risk of pipeline overpressurisation shall be controlled by pressure safe guarding systems in accordance to SP-1079.

The safety risk of pigging operations shall be controlled by regular maintenance of the pigging facilities and use of a procedure for pigging operations (PR-1082).

The economic risk of pipeline blockage by pigs shall be controlled by proper selection of pig types and assessment of pipeline piggability. Pig selection shall be based on the type of cleaning or other function required. UEL (CFDH Pipelines) shall be consulted when the use of non-standard pigs is contemplated.

The risk presented by unauthorised third party activities can only be controlled by regular Right of Way (ROW) inspections and visual/camera monitoring of fenced areas. Aerial or satellite reconnaissance is technically feasible but, given the low threat of sabotage on pipelines in Oman this not considered necessary.



2.3.5 Risk Recovery

Risk recovery shall be assured through the implementation of an emergency response system, including preparation and regular updating of an Emergency Response Manual, qualified pipeline repair procedures and emergency material stocks. Requirements and responsibilities for establishing and maintaining the response system are detailed in Section 2.5 of this specification.

2.4 Pipeline Integrity Activities

The key activities required to assure integrity of the PDO pipeline and flowline systems during their operation, maintenance and abandonment are detailed in the following sections. Inspection and Maintenance Records are kept by TTO/14. These records form the basis for the “Pipeline Annual Report”, which is produced following the Pipe-RBA Methodology in accordance with PR-1416.

2.4.1 Commissioning and Handover

Commisioning and handover procedures shall follow COP117.

For all class 1 lines, the documentation shall include the scope and frequency with which the parameters and product quality are checked/reported to the Asset Custodian and corrective procedures. Any deviation from the design intent and effect on asset integrity shall be included in the Asset Custodian monthly report.

2.4.2 Operations

The asset custodian, in liaison with support groups, shall plan inspection and maintenance activities in line with the approved “Pipeline Annual Report”.

The plans shall comprise, as a minimum:

Review of the operating envelope. Review of maintenance and inspection results. Review of performance against targets. Review of integrity and expected trends. Review of repairs and modifications. Review of emergencies and emergency exercises held. Proposed activities, action parties, frequencies and budget. Targets for performance indicators (e.g. leak records). Indication of estimated remaining life and present capacity.

Progress shall be reported to the Asset Holder on a monthly basis, with minimum reporting requirements as listed in Section 2.7 of this Specification. A quarterly review of the results shall also be conducted during implementation of the plan. This shall assess maintenance performance, recommend any necessary improvements that may be indicated and confirm the integrity status of the line.

The Integrity Reference Documents shall be updated continuously as maintenance and inspection results are received and integrity reviews completed.



2.4.3 Maintenance

2.4.3.1 General

The pipeline maintenance and inspection programme shall follow the Maintenance process given in CP-114. Minimum requirements for inspection and maintenance depend on the pipeline class and service. SAP-PM shall contain task lists and Maintenance Craft Procedures for all routine maintenance and inspection activities. Work Orders shall be raised by SAP-PM and the history of all activities shall be captured in the SAP-PM system in addition to the Corrosion Management System database, PACER-CMS and Pipe-RBA software.

The Asset Custodian shall raise the yearly budget on the basis of the recommendations in the Integrity Reference Documents and prioritization of the activities.

2.4.3.2 Planned Maintenance Activities

2.4.3.2.1 Routine Pigging (metallic pipes)

Routine pigging (in accordance with PR-1082) shall be done for all piggable pipelines as a first line of defence in corrosion mitigation to prevent corrosion product build-up, debris collecting in the line and/or removal of deposited water at low points. The frequency is dependent on flow conditions and corrosive conditions in the line and shall be determined through experience for each individual line. Until such experience is gained, the target frequencies are as follows:

Oil lines; weekly to bi-weekly. Wet gas lines; weekly to bi-weekly(a).

Dry gas lines; every 3 to 6 months(a). Dry gas with internal coating; every 6 to 12 months. PE-lined water injection lines (b); only when fouling is suspected. Internally FBE-coated lines (b); only when corrosion products are suspected to be

present.

Note (a); Piggability of gas pipelines with operating pressures below 30 bar shall be authorised by a pipeline engineer with TA-2. Pigging in gas pipelines shall not be carried out below an operating pressure of 10 bar.

Note (b); Until sufficient experience is gained, the lining/coating manufacturer's recommendation in pig selection shall be followed.

2.4.3.2.2 External Condition Monitoring

Routing monitoring shall include:

Checking for leaks. Third party activities, especially excavations. The condition of the ROW strip and windrow. Cover and position of the pipe at wadi and road crossings. Soil subsidence at falaj crossings. Monitoring of known leak sites. Condition of pipeline markers and barriers. Checking that above grade lines are well supported and clear of sand.

Lines in ‘medium’ or ‘high’ environmentally sensitive areas (as defined by PDO’s Environmental Advisor, CSM/2) shall be patrolled once per week. All other pipelines and flowlines shall be patrolled at least once per month.



For flowlines within the field development area (i.e overlying the reservoir) or shorter than 10 km, this ‘patrolling’ may be deemed to be covered by routine travel of operators, or other PDO/Contractor staff, as long as a formal reporting format is used and it can be demonstrated that all flowlines are being monitored on a regular basis.

All flowlines outside the field development area or longer than 10 km shall be patrolled once per month as a planned activity. (Patrols may take place on foot, by car, by aircraft or by satellite photography). Frequency for other locations where corrosion is susceptible and where leaks occurred in the past shall be increased. Patrol reports shall be filed with the Area Coordinator irrespective of whether leaks are detected.

All leaks, including recurring leaks at a known leak site, shall be reported to CSM and the local Area Coordinator on the form titled ‘PDO ENVIRONMENTAL INCIDENT/LEAK/ SPILLAGE NOTIFICATION’ contained in Part 1 of HSE/97/01 'Incident Notification, Investigation, Reporting and Follow-up’. The Area Coordinator shall ensure that the leak details are entered in the web-based leak database within 24 hours. The local population of employees, contractors and locals should be actively encouraged in the reporting of leaks and other integrity deficiencies.

A detailed Right of Way (ROW) survey shall be performed on an annual basis for all lines in location Class 2 or higher (location class as defined in ASME B31.8) and shall cover changes in land use and re-evaluation of population densities and habitation distances. Special points such as wadi crossings shall be inspected more frequently, especially following heavy rain.

Pipeline external coating and cathodic protection system performance shall be checked by means of CIPS/DCVG surveys. The frequency is to be set by a TA-2 materials & corrosion engineer. Typical frequencies vary between 3 and 6 years depending on the coating condition and criticality of the pipeline. Intelligent pig survey results should also be checked for correlation with external coating condition during integrity review exercises.

The external corrosion rate shall be assessed on a quarterly and annual basis making use of the ACR procedure, PR1503. The results shall be reviewed periodically, but at least annually, with the objective of verifying the effectiveness of the external corrosion control strategy. The review shall be coordinated by the Asset Custodian with input from the various support groups such as pipeline engineering, corrosion, materials and production chemistry specialists.

Buried unpiggable pipework on all Class 1 Pipelines at Block Valve Stations and scraper traps shall be excavated and inspected for internal and external corrosion once every 10 years using UT techniques.

Surface-laid pipelines and flowlines, external corrosion shall be measured yearly in locations where external corrosion is suspected or known. Displaced lines shall be put back on supports and made free of blown sand. For surface lines which do not need to have an intelligent pigging survey done, a selected number of road crossings shall be excavated every 10 years as a minimum to check the external coating condition. The selection of road crossings should preferably be based on Long Range UT inspection. Further details can be found in the guidelines for the protection of buried sections of surface laid pipelines/flowlines, GU-368.

2.4.3.2.3 Internal Condition Monitoring (metallic pipe)

Routine internal pipeline monitoring operations shall be performed on all piggable lines. Pigging data shall be gathered for trend analysis as an early warning for loss of integrity. Initially, the frequency shall depend on the risk rating of the pipeline and may be varied when operating experience with the line is built up.

Minimum recommended activities are:



Product analysis and corrosivity assessment to screen lines most at risk every 3 months. Examination of corrosion coupons and probes. Initially, these shall be retrieved with

such a frequency as to provide at least one result per 3 months. This frequency can be optimised once experience is gained with the pipeline and no changes in operating conditions occur.

Analysis of pig debris, shall be carried out when any sudden increases in debris returns are observed.

Intelligent pigging of piggable lines as specified in section 2.4.4.2. MFL inspection for non-piggable headers and flowlines.

The internal corrosion rate shall be assessed on a quarterly and annual basis making use of the ACR procedure, PR1503. The results shall be reviewed periodically, but at least annually, with the objective of verifying the effectiveness of the internal corrosion control strategy. The review shall be coordinated by the Asset Custodian with input from the various support groups such as pipeline engineering, corrosion, materials and production chemistry specialists.

Pressure testing in isolation of other measures shall not be accepted as a method of demonstrating the technical integrity of a pipeline since it does not allow corrosion presence or trends to be established.

PE lined pipes shall be checked yearly by venting the annular space in order to confirm the integrity of the liner.

2.4.4 Inspection Activities

2.4.4.1 General

A Pipe-RBA assessment of all Class 1 pipelines shall be made following an inspection, change in the corrosion rate, or change in an operating parameter of the pipeline. Further details can be found in PR1416. Class 2 and 3 pipelines may be carried out on a lower frequency as agreed with the asset team. The integrity status and the required integrity activities shall be captured in the Pipeline Integrity Reference Documents (these documents include the Pipe-RBA report). The reports shall be authorized by a TA-2 Corrosion Control Engineer.

2.4.4.2 Intelligent pigging, UT and MFL measurement (metallic pipe)

This specification recognises the useful experience that has been gained over the years on PDO pipelines and flowlines by the Asset Holders. The knowledge base has now expanded to include an abundance of data for corrosion management tasks. Therefore, for existing pipelines for which sufficient experience and suitable inspection data exist, the risk-based inspection of PIPE-RBA shall be applied, using the methodology outlined in PR-1416. For this group of pipelines the following outcome shall be obtained from the PIPE-RBA analysis software, but subject to the confirmation of an integrity review team:

- Integrity status (colour coding scheme).- Remaining life indication (in years).- Any corrective actions required.- Next inspection due date (with an interim inspection frequency factor).

For new pipelines, (or existing lines where integrity history has not been built up), the following inspection measures shall apply after the base-line inspection:

Class 1 piggable lines to be inspected by intelligent pig in the next 3 years, and then transferred to PIPE-RBA assessment subsequently.

Class 1 above ground non-piggable lines, to be inspected in full length by external MFL in the next 3 years for pipelines with diameter less than 12”, however for lines above 12” Long Range Ultrasonic (LRUT) can be used, and then transferred to PIPE-RBA assessment subsequently. Locations to be inspected using LRUT can be identified with consultation of a material & corrosion engineer with TA-2.



Class 1 buried non-piggable pipelines, on basis of a dedicated inspection plan that is authorized by a TA-2 Materials & Corrosion Engineer. Typically the plan should contain extensive ultrasonic inspection on a number of excavated pipe joints.

Where an Intelligent Pigging is the choice, the ratio of intelligent pigging and follow up repair costs versus pipeline replacement value shall not exceed around 10% per run to prevent excessive operating cost compared to a strategy of replacing the line on a regular basis.

UT measurements shall be made at locations where internal corrosion is most likely to occur as recommended in GU-432. For Class 1 lines, UT measurements shall be automated while for Class 2 and 3 lines, the UT measurements may be manual. A minimum section length of 1 metre shall be examined.

The initial UT measurements shall be over the full circumference of the pipe. If a defect is found, then a contour map shall be established by automated UT and follow-on inspections using automated equipment shall be performed every 6 months or as deemed necessary by a TA-2 Materials & Corrosion Engineer. Depending on the corrosion rate (established yearly), a decision shall be made whether to repair the affected section (if the MAOP is threatened) or to continue to monitor. If no defects are found, then checks at additional locations may be performed during the next inspection cycle.

If internal corrosion is found, then permanent UT pits to monitor the corrosion growth should be considered at a number of selected locations where the corrosion is known to be active.

UT measurements may also be taken in existing corrosion monitoring pits to substantiate corrosion coupon readings. This method shall be considered in all locations where coupon results indicate corrosion in excess of the corrosion design criteria.

Further requirements for inspection of non piggable lines, including class 2 and 3, are currently being included in the draft of GU-434 (Guidelines to demonstrate integrity of non piggable lines) which is under review for approval.

2.4.1. 3 Pipeline Accessories Inspection

Pig traps: end closure seal and bleed lock shall be inspected before every pigging operation both at launcher and receiver as specified in PR-1082. Internal and external condition of the barrel, end closure and associated valves shall be determined by visual inspection. Valves shall be maintained twice per year. Pig trap designs shall be verified to be compliant with SP-1268. Where deviations are noted, they shall be discussed with the CFDH pipelines, UEL and rectified where necessary.

Piping designed to ASME B31.4 or B31.8 (e.g. associated with the pig trap or pipework within the BVS fence) shall be inspected on a yearly basis by visual and UT methods. Inspection shall cover low points, elbows and any areas where erosion could occur due to high velocities. After 2 years, the inspection frequency can be optimised via the yearly pipeline integrity plan. Additional requirements shall be applied to any piping that requires main line shutdown to carry out repairs. These shall include auto-UT of horizontal pipe runs and angle probe examination of welds.

Insulating joints; the electrical isolating capacities shall be checked yearly.

Chemical injection facilities and sampling points shall be inspected yearly during routine monitoring/maintenance.

Instrumentation; control and protective equipment shall be inspected yearly and the settings checked to confirm that they concur with the operating envelope of the pipeline.

Relief valves shall be tested every 2 years, increasing to 5 years depending on performance.

ESD valves; the testing frequency shall be 3 times per year, which can be done on an opportunity basis. The maximum time interval between 2 tests shall be 6 months, unless otherwise specified.


Michiel Jansen, 05/08/03,

Where does this come from. Buried piping often has no CP and therefore needs to be inspected by excavation and not CIPS/DCVG. See also requirements in the external condition monitoring section.


Block valve stations; the testing frequency shall be 2 times per year and can be done on an opportunity basis. The condition of the site, warning signs and fence and the availability of keys shall also be checked.

CP transformer output shall be checked on a monthly basis. Potential recording at test points shall be checked every 3 months. On/off potentials shall be taken every year and shall replace that quarter’s on potential readings

2.4.4.4 Loading Lines

Inspection requirements for the loading lines running from the terminal to the SBM are:

Internal inspection using self-propelled umbilical controlled UT tool with frequency of inspection using RBA and automated UT at PLEM every 5 years.

Diver inspections or remote operated vehicle survey every 3 years. Diver inspections at critical locations and PLEM every 6 months. ESD and isolation valve testing; onshore 4-monthly, offshore 6 monthly intervals. CP transformer checked once per month.

The inspections should reveal:

Any damage to the pipeline or external coating (weight coating) and appurtenances. Any change in position of the lines. Extent of subsidence and silting. Whether free spans are within allowable limits. Presence of debris and condition of seabed in vicinity. Extent of marine growth. Effectiveness of CP. Operability of isolation and ESD valves. Condition of anodes.

2.4.4.5 Flow Lines

Inspection requirements for flowlines/headers are currently being included in the draft of GU-436 (External MFL Inspection Guidelines) which is under review for approval.

2.4.5 Defects Assessment And Remedial Actions

This section deals with defects in the body of the pipe which have smooth contours and cause low stress concentration, e.g. due to corrosion or corrosion-erosion effects. Other defects should be treated as per ASME B31.4/B31.8. Scheduling of pipeline repairs and pipeline replacement based on defect assessment and the use of a risk-based approach to prioritise and rationalise maintenance programmes.

Sections 2.4.5.3 (Repairs) and 2.4.5.4 (Replacement) refer to maintenance activities which shall require careful planning into the Maintenance Plan.

For non-leaking pipeline defects with wall loss less than 70%, the time available prior to actual leak or rupture, within which a repair must be scheduled and executed, shall be estimated using one or more of the following tools/procedures:

Assess Pipe/Pipe-RBA programs. UT checks/verification. IP results.

This shall be reflected in the Pipeline Reference Document and normally executed within one year of the inspection survey.



SP-1180 provides the key guide in the choice of intelligent pigs, sizing and detection accuracies, reporting formats and fitness-for-purpose analyses. The applicable procedure for pipeline derating is PR-1010 and for the execution of all remedial work, SP-1235 (DEP 31.40.60.12-PDO) and PR-1011.

2.4.5.1 Defect assessment

Defects shall be assessed in line with the pipeline design codes guideline of Shell 92 (detailed in document AMER 96.010), wherein the procedure for determining the remaining strength of corroded pipe is provided.

Prior to physical repair of a pipeline, defects need to be assessed accurately to determine the optimal repair method and location. External defects shall be assessed with depth gauge measurements and results should be evaluated in AssessPipe Software. Potential deterioration and the possibility of future requirements for monitoring shall also be considered. For internal defect validation, UT measurement shall be done as provided for in section 2.4.3.5.

For deterministic assessment of defects (including growth) from intelligent pigging data, the software package Assess-Pipe shall be applied. The Assess-Pipe software is integrated in Pipe-RBA.

In addition to the foregoing, the asset owners’ future requirements for continued service may be such as to improve the overall integrity status of the pipeline. This approach requires both fit-for-purpose (FFP) assessments for the present status whilst incorporating future changes in capacity. For this analysis, quality inspection data shall be gathered and PIPE-RBA analysis shall be used to build up an integrated MAOP buy-back plan to manage integrity and capacity problems.

2.4.5.2 Derating

For derating procedures, reference shall made to PR-1010.

2.4.5.3 Repairs

For the repair methods and strategies, reference shall be made to SP-1235 and PR-1011.

Additional requirements:

The repair strategy to be adopted in the case of defects shall be determined according to the measured metal loss, as follows:

For non-critical defects (i.e. with wall loss less than 10%) it is technically acceptable to leave the defect without repair provided that the coating is restored to prevent further attack.

For defects causing wall loss of more than 10% but less than 70% the remaining strength shall be determined using SP-1180 and Shell92. A decision may then be taken to repair or only to restore the coating.

All defects extending beyond 70% or more of the wall thickness are considered critical and shall be repaired without delay.

All defects with remaining wall thickness of less than or equal to 2mm shall be repaired without delay.

For the repair of critical external defects, epoxy grouted sleeves are the first choice. The 'clock spring' repair method is also potentially available, depending on the severity of the defects. The decision of which repair method to be selected is to be taken by a pipeline integrity engineer with TA-2 in consultation with UER/UEL.

Depending on severity, leaking defects may be temporarily repaired using proprietary clamps. A permanent repair for leaks on Class 1 pipelines, consisting of a replacement



section, shall be made within 3 months, unless replacement of the whole line has been initiated. Where a PLIDCO type clamp has been deployed to stop a leak, a permanent repair brought about by complete welding of the clamp to the pipeline shall be equally acceptable as an alternative provided the operational safety issues have been properly addressed. On Flowlines and Class 2 and 3 lines proprietary clamps may be employed for permanent repairs except in the following cases:

Buried lines. H2S content of the transported fluid is 500ppm (v/v) or more. Operating pressure exceeds 9000kPa. Leaks situated on-plot in lines transporting gas or live crude.

In these cases a permanent repair shall be completed within 3 months, as for Class 1 lines.

2.4.5.4 Replacement

Lines shall be replaced when the pipeline integrity objectives can no longer be achieved. The decision to replace a line shall be made by the Asset Holder in consultation with the pipeline, corrosion and materials engineering support groups.

Some conditions for pipeline and flowline replacement are as followed:

The line can no longer be operated to the desired operating envelope; e.g. a required increase in capacity cannot be catered for, or the MAOP has to be derated to an unacceptable level.

Projected operational expenditure is no longer economical. This shall include all anticipated repair costs, clean-up costs of leakage and loss of revenue. For flowlines this point typically will be reached when the sustained repair costs exceed around 8% per annum of the flowline replacement cost or when the projected leak rate exceeds more than 2 leaks/km/year.

The remaining life of a pipeline in service shall be determined using the PIPE-RBA process to check the optimum replacement time, which is consistent with the most economic maintenance strategy. A corrosion expert’s input in the determination of the future corrosion rate for each pipeline shall be sought and agreed before establishing a remaining life.

The remaining life of a pipeline in service so determined using the PIPE-RBA program shall be subject to a life span optimisation study by the asset owner. This shall take into account failure modes, corrosion rates and potential economics for possible sleeving, derating strategies, and/or chemical injection to mitigate corrosion.

2.5 Emergency Response

Detailed Emergency Response Procedures shall be available, owned by the asset holder as defined in MS1001. The emergency response documentation shall include contingency plans to deal with a number of realistic emergency situations. Oil spill or gas leak sensitive areas, e.g. where oil spills can enter the water table or have an impact on inhabited areas, shall be clearly identified and measures indicated to limit damage to people and the environment. Pipeline leak detection systems and/or line break valves should be considered where appropriate. Pipeline related emergency response documents currently issued or in preparation are included in the PDO references in Appendix B.

Emergency repairs to the pipeline system shall be in accordance with GU-379, Emergency Repair Manual, owned by the Pipeline CFDH. The holder and users are the Operations and Engineering technical support team. This manual specifies repair methods/materials, and incorporates qualified pipeline repair and replacement procedures for emergency use.

Critical pipeline repair equipment and consumables shall be identified and arrangements made to have this equipment available in an emergency.

An adequate emergency stock of linepipe and pipeline repair fittings shall be kept, owned and maintained under the control of the pipeline group, within the Technical Services



organisation. Materials shall be inspected on a yearly basis and a maintenance programme shall be operated, owned by the pipeline CFDH.

The emergency plans shall be tested on yearly basis.

2.6 Performance Review And Abandonment

For the Operations, Maintenance and Abandonment of PDO pipelines the following Performance Indicators should be applied and reported in accordance with PR-1012 and for abandonment and restoration, reference should be made to PR1071, PR1164, and PR1419:

(i) Operate and Maintain

Number of leaks (containment integrity). Inspection indicators. Maintenance indicators. Reliability indicators. Pipeline condition (MAOP/Design MAOP, traffic lights). EOM effort (cost of planned Opex and Capex against plan). Integrity Management reviews.

(ii) Abandon

Existence of proper documentation /procedures/registration. Actual execution. Opportunity case identification (e.g. re-use).

Appropriate indicators shall be reflected by the Asset Team for each section of their pipelines in the yearly review report.

2.7 Documentation and Information Systems

2.7.1 Plans

The pipeline plans to be prepared and maintained have been described earlier in Sections 2.4.2 and 2.4.3 of this document. These are summarised in the following table:

Table 2 - Summary of Pipeline Plans

Plan Compiled by Contents



Is specified in SP-1209


ARP Asset Custodian Detailed pipeline data and description of planned activities to be performed over the life cycle. Provides the base data for development of the annual and 5 year plans below.

Pipeline Reference Document (RBA Report)

Pipeline Maintenance & Corrosion Services (TTO/14)

Rolling plan comprising a review and forecast of integrity status/activities from which budget requirements can be developed. To be updated continuously as activities and integrity reviews are completed.

25 year look-ahead

Asset Integrity Group

Annual overview based on the above plans indicating replacement programmes and expenditure phasing over the period.

2.7.2 Information Systems

2.7.2.1 General

The asset holder in each phase of the pipeline shall be responsible for preparation, updating, retention and distribution of documents and data.

For storage of fixed pipeline data and inspection data PACER-CMS and SAP-PM shall continue to be used and, for drawing registration and storage, the PDO central drawing archive, IDAS. However the development of a linked database and archiving system shall be put in place to enable rapid selective retrieval of specific pipeline data and records.

2.7.2.2 Development Phase

The documentation requirements shall be in line CP-117 and shall cover Project Definition and Execution Plans from the conceptual stage through to the execution phase.

The handover documentation shall be in line with the requirements of SP-1229 and SP-1211. Documentation shall be handed over to the asset holder and the custodian of the operations phase.

The main categories of documents which should make up the handover package on completion of a new pipeline are as follows:

As-built drawings and drawing data, route maps; Design, procurement, construction and commissioning documentation, including

material and test certification and Vendor records; Pipeline Design Reference Manual; Pipeline Operating Manual.

2.7.2.3 Operations Phase

Documentation requirements shall be in line with the Pipeline Operations Manual and SP-1229.

Maintenance data shall be kept in SAP-PM. Inspection results and basic design information shall be kept in the PACER-CMS and Pipe-RBA database. Integrity reports shall be kept in the Pipe-RBA software.

A set of as-built drawings should normally be retained by Operations along with the Pipeline Design Reference and Operating Manuals. However these requirements should be reviewed as electronic storage and retrieval systems are developed further.



I recommend not to specify to documents that still need to be developed.


2.8 Control Framework

Business controls for pipeline integrity shall be subject to periodic (minimum every 3 years) internal audit and review as directed by the pipeline CFDH. The scope shall include both technical reviews of specific pipelines or plans and management system audits of the whole Pipeline Integrity Management System (PIMS).

Key performance indicators shall be compiled to monitor integrity activities and the resulting pipeline performance. In addition, a monthly overall status report for all Class 1 pipelines shall be prepared. The KPI’s and status reports should be agreed with the relevant Technical Integrity Steering Committee(s).

2.9 Effective Period

The requirements of this specification shall remain in force indefinitely unless superseded by an authorised revision.

2.10 Review and Improvement

This specification will be reviewed and updated once every three years. The review authority will be UOX, (CFDH Technical & Operational Excellence).



Specified in SP-1209


This is overlapping with the review (e.g. FAIR at end of 2003) that is instigated by the Maintenance Process Owner UOX.


Appendix A - Glossary of Terms, Definitions and Abbreviations

A.1 Terms and Definitions

Flowline A pipeline between well-head and gathering facility/manifold or vice versa. Typical flowlines are those transporting unprocessed hydrocarbons to a gathering station/manifold, water injection lines transporting water from a treatment/pumping station to the wellhead and gaslift lines transporting high pressure gas from compressors stations/manifolds to the well head.

Header A header is defined as a pipeline which carries fluid from more than one source or to more than one destination.

Pig A device which is driven through a pipeline by the flow of fluid (or by a connecting retrievable cord) used to perform various internal activities depending on type. Examples include those for cleaning, fluid separation/batching gauging, profiling & inspection.

Pig Trap An ancillary equipment item fitted or installed at the end of a pipeline with associated pipework and valving arrangements to accommodate a pig either for its launching or retrieval.

Pipeline A series of jointed pipes transporting liquids or gaseous fluids or a mixture of both between (but excluding) gathering/production plants, pressure boosting stations, processing plants, storage and export facilities. It extends from pig trap to pig trap and includes the traps, associated pipework and valves. Where no pig trap is fitted, then it extends to the first isolation valve within the plant boundaries. The delineation between the pipeline and the station is the specification break between the pipeline design code ASME B31.4/B31.8 and the piping design code ASME B31.3.

Pipeline Integrity A pipeline has integrity when it performs as intended whilst being operated as intended and has a tolerable risk of failure over its service life.A pipeline has design integrity when functional performance standards and operating conditions relevant to functional performance have been quantified, physical behaviour relevant to functional performance has been modelled and analysed, and possible functional failure modes have been considered, resulting in a redesign or specified operating and maintenance requirements.A pipeline has technical integrity when, under specified operating conditions, the risk of failure endangering the safety of personnel, environment or asset value, is as low as reasonably practicable.A pipeline has operating integrity when it is being operated as intended, such that it can achieve the production target without attracting undue risk to personnel, environment and assets.

Pipeline System As a part of an Integrated Production System, a pipeline system comprises a main transport line and all associated installations that influence its operating envelope from the point of inventory receipt, including physical installations for inventory monitoring and its controls up to the point of inventory discharge to say, a station or terminal. The system in this respect includes components such as pumps and compressors, pressure limiting stations, metering, road and wadi crossing isolation valves, remote sensing communication and installations/SCADA connections



A.2 Abbreviations

ADP Asset Development PlanARP Asset Reference PlanBCD Business Control DocumentsBS&W Base sediment and waterBVS Block Valve StationCFDH Corporate Functional Discipline HeadCIPS Close Interval Potential SurveyCOP Code of PracticeCP Cathodic ProtectionDCS Document Control SystemDCVG Direct Current Voltage GradientEIA Environmental Impact AssessmentEOM Extraordinary MaintenanceESD Emergency ShutdownFBE Fusion Bonded EpoxyFCP Field Change ProcedureHAZOP Hazards and Operability StudyHEMPS Hazard and Effects Management ProcessIP Intelligent PigMAOP Maximum Allowable Operating PressureMFL Magnetic Flux LeakageMOL Main Oil LineMOP Maximum Operating PressureMRP Maintenance Reference PlanORP Operations Reference PlanPACER-CMS PACER Corrosion Management SystemPEP Project Execution PlanPFAT Product Flow Asset TeamPLEM Pipeline End ManifoldRBA Risk Based AssessmentRBI Risk Based InspectionRBM Risk Based MaintenanceRCM Reliability Centred MaintenanceROW Right of Way (Pipeline Corridor)SAP-PM System Application and Product – Plant MaintenanceSBM Single Buoy MooringSGSI Shell Global Solutions InternationalSIEP Shell International Exploration and ProductionSOGL South Oman Gas LineUT Ultrasonic Testing



Appendix B References

In this specification, reference is made to the following documents:

PDO Documents

Corporate Management Framework (CMF)

Product Flow Asset Integrity Management System (PFAIMS) Manual

Policy Statement

Product Flow Asset Integrity

Code Of Practice (COP)

Maintain Surface Product Flow Assets

Operate Surface Product Flow Assets Project Engineering

Specification

Process Safeguarding Specification

Intelligent Pig Inspection of Pipelines

Pipeline Construction Specification

DEP 31.40.00.10-PDO Pipeline Engineering

Specification for Handover and As Built Documentation (in preparation)

Dep 31.40.60.12-PDO Pipeline Repairs (Supplements to ASME B31.4 and B31.8)

Construction of Pipeline Systems in Non-Metallic Materials

Design of Pipeline Pig Trap Systems

Procedure

Pipeline Derating Procedure

Pipeline Remedial Work Procedure

Composite Integrity Performance Indicator Compilation

Flow and Gaslift Line Suspension/ Abandonment Procedure

Pipeline Pigging Launch & Retrieval Procedure

Fixed Asset Abandonment Procedure

Procedure for the Use of PIPE-RBA Methodology

MS 1001

PL-32

COP-114

COP-115

COP-117

SP-1079

SP-1180

SP-1208

SP-1211

SP-1229

SP-1235

SP-1247

SP-1268

PR-1010

PR-1011

PR-1012

PR-1071

PR-1082

PR-1164

PR-1416

PR-1503



Procedure for Assessed Corrosion Rate

Procedure for Abandonment And Restoration

Guideline

Guideline for Granting Technical Authority System

Guidelines For The Protection Of Buried Sections Of Surface Laid Pipelines/Flowlines

Pipeline Emergency Repair Manual

Guideline for the Auto UT inspection planning of Class-1 pipelines

Guidelines to demonstrate integrity of non piggable lines

External MFL Inspection Guidelines

Other Documents

Integrated Operations Plan

PACER-Corrosion Management System, Technical Reference Guide

Pipelines HSE Case

PR-1419

GU-272

GU-368

GU-379

GU-432

GU-434

GU-436

Yearly Edition

PCM-TECH-5/03

Shell Group Documents

Burst criteria of corroded pipelines – defect acceptance criteria, SIOP, June 1996

Pipeline Integrity Management; Guide to Pipeline Risk Based Assessment

AMER 96.010

OP.01.20087

American Standards

Chemical Plant and Petroleum Refinery Piping

Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia and Alcohols

Gas Transmission and Distribution Piping Systems

ASME B31.3

ASME B31.4

ASME B31.8

Issued by:

American Society of Mechanical Enfineers Publications and Distribution Section 1220 L Street Northwest Washington DC 20005 USA

Software

Assess Pipe Program, Version 2

Pipe-RBA

ACR

SIEP, 1996

SGSI, 2002

TTO14





Appendix C Failure Mode & Effect Analysis; Basis and Examples

C.1 General

This appendix outlines the basic procedure to be adopted for FMEA. Tables D1 and D2 summarise typical FMEA matrices, respectively for technical and operational integrity and illustrate the integrity parameters that may be considered in the analysis.

C .1.1 FMEA Process

The methodology for FMEA includes:

(i) Identification of the principal pipeline failure mechanisms. Examples in PDO span internal corrosion, external corrosion, internal erosion, impact damage/overpressure, subsidence/wadi wash-outs, pipeline blockage, slugging etc.

(ii) Analysis of the failure process is required from the stage of 'triggering' of the phenomenon up to the actual occurrence of failure. This knowledge of the process breakdown should clearly identify subsequent 'cracks' in the 'barrier'. For example, for a pipeline failure mechanism identified as external corrosion a possible failure process may commence with CP failure, or for above ground lines, contact with soil/sand due to loss of support or to the accumulation of wind blown sand on the ROW. This is followed by coating breakdown and 'active corrosion', leading finally to the appearance of 'defects'.

(iii) Control measures in response to each of the identified process elements which could lead to a failure can thus be comprehensively identified and preventive actions/measures selected.

(iv) Having recognized the process and controlling parameters as described, a positive effort can then be made to assess the effectiveness of the preventive measure taken in (iii) above. For example, the effectiveness of a coating may be confirmed through a coating survey for which various techniques have been tested, qualified and approved, including CIPS, DCVG, Pearson survey, etc. For internal corrosion, once the type of corrosion mechanism is identified, the parameters that trigger and influence the particular form of corrosion should then be measured at appropriate intervals to establish if they are in line with the operating envelope and to determine if and what changes have occurred. For example, the MOL is designed without corrosion allowance, so any indication of ongoing activity, whether internal or external, shall trigger an integrity review of the failure mechanism, once it has been verified that corrosion persists despite the preventative and mitigating measures taken.

(v) Inspection, on a periodic basis shall be carried out once defects are known to be present in a pipeline or flowline or as part of the positive confirmation that technical integrity exists.

(vi) The final step is to review the process and recommend operational changes or methods of repair. These may include, for example, line derating, epoxy grouted sleeving repair, corrosion inhibition, sectional replacement, PE lining etc.

A comprehensive tabulation showing typical FMEA parameters is presented in Tables C1 and C2, following.



Table C.1 - Technical Integrity

FAILURE MECHANISM

TRIGGER MECHANISM

CONTROLLING PARAMETERS

TECHNICAL INTEGRITY

PARAMETERS

PREVENTIVE/MITIGATION OPTIONS

EXTERNAL CORROSION

Coating breakdown/ disbondingImpactCP Interference or breakdownUnder-clamp condition

Coating conditionCP potentialSoil resistivityPresence of foreign objects

Rem. wall thickness (RWT)Estimated Repair Factor (ERF)CP potentialRe ValueResistance of insulationRemaining life of sacrificial anodeImpressed current system condition

Coating inspection & repairFlowline lifting onto supportsSacrificial anode depletion surveyRectifier inspection/ monitoring

INTERNAL CORROSION

CO2H2SSRBO2WaterGlycolAcidsErosion/corrosion

CO2 contentDew PointInternal pressureTemperatureBS&WFlow rateInhibitor concn.Scale/debrispHPresence of salts (carbonates, sulphates)Cleanliness

RWTERFRemaining life/design lifeActual inhibitor/required inhibitorActual biocide/required biocideActual dew point/required dew pointPigging frequencyFree water factor (emulsion)Debris/sand content entrained in flow

Design (material selection)Routine piggingChemical inhibitionDehydrationDew pointPigging residue analysis and quantityChemical cleaningFloline7 input dataExternal UTCorrosion couponsSand probes

High flow rates (presence of particles)

Fluid velocityFlow regimeBend geometrySand content

Actual/allowable erosion rates

Upstream condition mgt.Corrosion allowanceMaterials selectionWell repair (e.g. gravel packing or sand consolidation)

IMPACT MissileVehicleBoatDropped objectsCablesThird Party

Escalation from unrelated eventFencesFendersMarkers, navigation lightsCaissons, J-tubesProhibited accessConcrete coatingPipeline routingRock dumpingCrane lifting proceduresCable frettingExcavationEncroachmentSabotage

Exposed length/protected length% structure without fendersIncidents recordDent depthPresence of gougesPipeline drag/shiftAnchor hanging procedure/patterns

Safety CaseVisual inspection% structure with navigational lightsIncident monitoringLine verification procedureInspection and rehabilitationBuried linesAnchor pilesRoad crossingsMovement breakersWarning signs/postsROW surveillance & inspectionEviction orders

EXPLOSION, FIRE

Escalation from unrelated incident

Develop Safety Case

PIGTRAP OPERATION

Deterioration of door sealFailure of door safety lock

Double block and bleed valvesPurge facilitiesPigtrap facilitiesPigtrap proceduresDoor interlocksEarth bonding

AuditingPigtrap and valve maintenancePig signallers

EXCESSIVE LOADING

Internal PressureSubsidence/Washout (onshore)Spanning (offshore)

RWTPressure

% relief valves failing test% relief valves certified% trips failedSpan lengthDepth of sag

Pressure transmitterRelief valve settingShutdown systemBackfillStrain gaugesRouting pigsExternal profilingROV surveySidescan sonar

MATERIAL/ WELD DEFECTS

Internal pressurePressure/stress fluctuations

QA/QC during manufacture and construction

Table C.2 - Operational Integrity

FAILURE MECHANISM

TRIGGER MECHANISM

CONTROLLING PARAMETERS

TECHNICAL INTEGRITY PARAMETERS

PREVENTIVE/MITIGATION OPTIONS



BLOCKAGE(Full or Partial)

WaxScaleSandPigging operationsConstruction materials

Composition of fluidPressureTemperatureFlow regimeFlow rate

Capacity/reqd capacityCapacity/design capacityNumber of blockagesAmount of debris per pig run

PiggingChemical treatmentMagnetic treatmentSand controlSand filteringFlushingSteam cleaningPressure drop monitoring

SEVERE SLUGGING

ObstructionTwo phase flowCondensation

Gas/Liquid RatioFlow rate and regimeBack pressurePressureTemperatureGeometry

Change operating conditionsCleaning/piggingProcedures



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