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Petroleum and Natural Gas Regulatory Board (Integrity Management System for Petroleum and Petroleum Products Pipelines) Regulations, 2021

Published vide Notification F. No. PNGRB/Tech/15-IMSPPPLReg. /(1)/2021-Volume (3) (P-3385), dated 27.08.2021

Last Updated 13th September, 2021 [act3941]

(a) "Act" means the Petroleum and Natural Gas Regulatory Board Act, 2006 (19 of 2006);

(b) "Appendix" means the Appendix to these regulations;

(c) "Board" means the Petroleum and Natural Gas Regulatory Board established under subsection (1) of section 3 of the Act;

(d) "Integrated surveillance system" means the pipeline surveillance for third party encroachment activities along ROU and such surveillance may use optical fiber cable, microwaves, and satellite as communication systems and could integrate SCADA's data;

(e) "Intermediate pump station" means the installation located at any place between starting point and the terminal point having pumps to enhance the pressure of the fluid to achieve desired flow rate;

(f) "Operator" means an entity that operates Petroleum and Petroleum Products Pipelines with the authorization of the Board;

(g) "Originating pump station" means facilities installed at the start of the pipeline system for developing required fluid pressure so as to achieve desired flow rates in the pipeline system;

(h) "Petroleum and Petroleum Products Pipeline" means any of the pipelines as defined under Petroleum and Natural Gas Regulatory Board (Authorizing entities to Lay, Build, Operate or Expand Petroleum and Petroleum Product Pipelines) Regulations, 2010;

(i) "Right of User (RoU)" means the area or portion of land with which the pipeline operator or owner has acquired the right through the relevant Statutory Acts or in accordance with the agreement with the land owner or agency having jurisdiction over the land to lay and operate the Petroleum and Petroleum Products Pipelines;

(j) "Risk" means the measure of potential loss in terms of both the incident probability (likelihood) of occurrence and the magnitude of the consequences of such occurrence;

(k) "Risk analysis" has the same meaning as the Risk Assessment defined in clause (h);

(l) "Risk assessment" means systematic process in which potential hazards from facility operation are identified, and the likelihood and consequences of potential adverse events are estimated and such risk may have varying scopes, and can be performed at varying levels of detail depending on the operator's objectives;

(m) "Risk management" means overall program consisting of identifying potential threats to an area or equipment; assessing the risk associated with those threats in terms of incident likelihood and consequences; mitigating risk by reducing the likelihood, the consequences, or both; and measuring the risk reduction results achieved;

(n) "Schedule" means the Schedule to these regulations;

(o) "Shall" indicates mandatory requirement;

(p) "Should" indicates a recommendation or that which is advised but not mandatory;

(q) "Subject Matter Expert (SME)" means an individual who possesses knowledge and experience in the process or discipline one represents as per ASME B 31 Q";

(r) "Terminal station" means a facility to receive products at the end of the pipeline and this may include the tankage for storage of petroleum and petroleum products;

(a) evaluate the risk associated with Petroleum and Petroleum Products Pipeline and effectively allocate resources for prevention, detection and mitigation activities;

(b) improve the safety of petroleum and petroleum products pipeline so as to protect the personnel, property, public and environment; and

(c) minimize the probability of failure of petroleum and petroleum products pipeline for streamlined and effective operations

(a) the entity shall be required to complete each activity within the time limit specified by the Board and if there is any deficiency in achieving in one or more of the activities, the entity shall submit a mitigation plan with time schedule to the Board and make good all short comings within the time schedule. If the entity fails to complete activities within the specified time schedule, relevant penal provisions of the Act shall apply; and

(b) in case the entity fails to implement the approved Integrity Management System, the Board may issue a notice to defaulting entity allowing it a reasonable time to implement the provisions of Integrity Management System and in case the entity fails to comply within such reasonable time, the relevant provisions of the Act and these regulations shall apply.

Schedules

(See regulation 6)

Schedule - 1

(a) ensure petroleum and petroleum products pipelines integrity in all areas which have potential for adverse consequences;

(b) promote a more rigorous and systematic management of petroleum and petroleum products pipelines integrity and mitigate the risk;

(c) enhance the general confidence of the public in the operation of petroleum and petroleum products pipelines; and

(d) enhance the life of the petroleum and petroleum products pipelines with the inbuilt incident investigation and data collection including review by the entity.

Schedule - 2

(a) Integrity Management Plan (IMP): This encompasses collection and validation of data, assessment of spectrum of risks, risk ranking, assessment of integrity with respect to risks, risks mitigation, updating data and reassessment of risk.

(b) Performance evaluation of IMP: This is a mechanism to monitor the effectiveness of integrity management plan adopted and for further improvement.

(c) Communication Plan: This covers a structured plan to regulate information and data exchange within and amongst the internal and external environment.

(d) Management of Change: This is a process to incorporate the system changes (technical physical, procedural and organization changes) into Integrity Management Plan to update the integrity management plan.

(e) Quality Plan: This is a process to establish the requirements of quality in execution of the processes defined in the Integrity Management Plan.

Schedule - 3

3.1 Physical Description: Description of Petroleum and Petroleum products pipeline shall include specific description of the pipelines, pumping stations, valves stations and major installations such as the following, namely: -

3.1.1 Steel Pipeline networks.

3.1.2 Storage facilities or tanks- atmospheric or low pressure or high pressure.

3.1.3 Pumping Stations or Intermediate Pump stations.

3.1.4 Sectionalizing Valve Stations.

3.1.5 Dispatch Terminal or Receiving Terminal.

3.1.6 Control Rooms.

3.1.7 Safety Equipment.

3.1.8 Intermediate Pigging Stations.

3.1.9 Tap-Off Stations.

3.1.10 Electrical System.

3.1.11 Cathodic Protection System.

3.1.12 Telecom or SCADA or Data Transfer System.

3.1.13 Spur-pipelines.

3.2 OTHER DESCRIPTION: The following are the other descriptions, namely: -

3.2.1 ROU Details-ROU width and constraints, if any.

3.2.2 Interfaces with other operators' facilities or pipelines, if any.

3.2.3 Historical background of the pipeline and major modifications and additions carried out in the system, if any.

Schedule - 4

Selection Of Appropriate Integrity Management System

Schedule - 5

Integrity Assessment, Monitoring And Surveys:

(a) Pre-assessment- incorporating various data gathering, database integration and analysis;

(b) Indirect Inspection- using either tools or calculations to flag possible corrosion sites, or calls, based on the evaluation or extrapolation of the database;

(c) Direct or Detailed Examination- excavation and examination to confirm corrosion at the identified sites and remediation as provided in Schedule 6; and

(d) Post-assessment - to determine the fitness for service of pipeline, re-assessment interval and effectiveness of Direct Assessment.

(i) Pipe to Soil Potential Survey;

(ii) Transformer Rectifier Unit or Cathodic Protection Power Supply Module - current and voltage monitoring method;

(iii) Closed Interval Potential Logging Survey;

(iv) Coating Health Surveys (Current Attenuation Test, Direct Current Voltage Gradient survey and Alternating Current Voltage Gradient Survey); and

(v) Pipeline AC and DC Interference Survey including survey at Foreign Pipeline Crossings, Power Transmission line crossings or parallelism and other Stray current sources. It shall be obligatory on all the entities involved to facilitate conduct studies or surveys and take mitigation measures.

(i) night patrolling by Line walkers or alternative security surveillance system where the pipeline location is vulnerable from security point of view

(ii) right of User tracking through satellite imaging methods for critical stretches of pipeline system

(iii) aerial survey of Right of User at critical and in-accessible stretches such as hilly regions and Ghat sections and like other regulations and section; and

(iv) identify the vulnerable locations from pilferage point of view.

1. Fiber Optics System

2. Ground Censor System

3. Radar based detection system

4. Fence secure data access system

Schedule - 6

Designing Applicable Integrity Management System For Petroleum And Petroleum Product Pipelines:

(I) Time Dependent Threats:

(1) Manufacturing related defects

(i) Defective pipe seam; and

(ii) Defective pipe

(2) Welding or fabrication related

(i) Defective pipe girth weld;

(ii) Defective fabrication weld;

(iii) Wrinkle bend or buckle; and

(iv) Stripped threads or broken pipe or coupling failure;

(3) Equipment

(i) Gasket O-ring failure;

(ii) Control or relief equipment malfunction;

(iii) Seal pump packing failure; and

(iv) Miscellaneous;

(III) Time independent Threats:

(1) Third party or mechanical damage:

(i) Damage inflicted by first, second or third party (instantaneous or immediate failure);

(ii) Previously damaged pipe (delayed failure mode); and

(iii) Vandalism;

(2) Incorrect operational procedure

(3) Weather related and outside force:

(i) Weather related;

(ii) Lightening;

(iii) Hydro technical: water-related threats including, but not limited to, liquefactions, flooding, channeling, scouring, erosions, floatation, breaches, surges, inundations, tsunamis, ice jams, frost heaves, and avalanches, creek area effects, river meandering, river bed or bank movement;

(iv) Geotechnical: earth movement threats including, but not limited to, subsidence, extreme surface loads, seismicity, earthquakes, fault movements, mining, and mud and landslides, muddy land effects; and

(v) High wind;

(i) Leak;

(ii) Mass release or Continuous release;

(iii) flash fire or Jet fire;

(iv) explosion;

(v) UVCE (unconfined vapour cloud explosion);

(vi) CVCE (confined vapour cloud explosion);

(vii) Gas cloud;

(viii) Fireball;

(ix) Pool fire; and

(x) Tank fire

(i) Prioritization of pipeline sections or segments for scheduling integrity assessment and mitigation plan;

(ii) Assessment of the benefits derived from mitigation actions;

(iii) Determination of the most effective mitigation measures for the identified threats;

(iv) Assessment of the integrity impact from modified inspection intervals;

(v) Assessment of the use of or need for alternative inspection methodology; and

(vi) More effective resource allocation.

(a) utilizing the services of Subject Matter Experts (SMEs);

(b) relative Assessment Model;

(c) scenario -Based Model; and

(d) probabilistic Models.

(a) they identify potential events or conditions that could threaten system integrity;

(b) they evaluate likelihood of failure and consequences;

(c) they permit risk ranking and identification of specific threats that primarily influence or drive the risk;

(d) they lead to the identification of integrity assessment or mitigation option;

(e) they provide for a data feedback loop mechanism; and

(f) they provide a structure and continuous updating for risk reassessments

(i) change in operating conditions such as pressure, temperature, flow, flowing medium and like other conditions;

(ii) changes in Right of Use conditions like development of encroachments, increase in third party activities or population density, major washouts;

(iii) pipeline Leak or rupture history;

(iv) addition of new or expansion of the existing railway or road or waterway crossings;

(v) changes to pipeline Cathodic protection levels due to external interference problems;

(vi) any other issues which may affect the integrity of pipeline; and

(vii) the results of previous integrity assessments.

(i) pressure testing;

(ii) inline inspection (ILI);

(iii) direct Assessment (ECDA, ICDA and SCCDA); and iv) any other Integrity Assessment methodology.

(a) Immediate repair conditions: Such indication shows that defect is at failure point which shall include but not limited to any corroded area having

(i) metal loss equal to or more than 80% of nominal wall thickness regardless of dimensions;

(ii) predicted failure pressure less than equal to 1.1 times the maximum allowable operating pressure (MAOP) as determined by ASME B31G or equivalent. Safety Factor, tool tolerance is not taken into consideration while calculating predicted failure pressure;

(iii) metal loss indication affecting a detected longitudinal seam, if that seam was formed by direct current or low frequency electric resistance weld or by electric flash welding;

(iv) crack or crack like anomalies greater than 70 % of nominal wall or of an indeterminate depth that exceeds the maximum depth sizing capabilities of the tool used in integrity assessment or Verified cracks except shallow crater cracks or star cracks in girth welds unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity or all indications of stress corrosion cracks (SCC);

(v) a combination of dent with gouge or possible crack or Stress riser unless an industry recognized engineering analysis shows that it does not pose an immediate threat;

(vi) a dent located on the top of the pipeline (above the 4 o'clock and 8 o'clock positions) with a depth greater than 6 % of the nominal pipe diameter unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity; and vii) any indication of adverse impact on the pipeline expected to cause immediate or near-term leaks or ruptures which include dents with gouges and like other devices.

(b) Scheduled conditions: Such indication shows that defect is significant but not at failure point. Following indications shall be examined within one year of discovery, namely: -

(i) an area of general corrosion, Selective Seam Weld Corrosion, area of widespread circumferential corrosion, area of girth weld, area located at another pipeline crossing with a predicted metal loss greater than 50 % of nominal wall;

(ii) predicted failure pressure less than equal to 1.25 times the maximum allowable operating pressure (MAOP) as determine by ASME B31G or equivalent (Safety Factor, tool tolerance is not taken into consideration while calculating predicted failure pressure);

(iii) crack or crack like anomalies with depth greater than 50 % of nominal wall;

(iv) a gouge or groove greater than 12.5 % of nominal wall resulting from mechanical damage;

(v) a dent falling under any of the following criteria, unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity, namely: -

(a) located on the bottom of the pipeline (below the 4 o'clock and 8 o'clock positions) with a depth greater than 6 % of the pipeline's diameter;

(b) that affect ductile girth or seam welds if the depth is more than 2% of the nominal pipe diameter (0.250 inch in depth for a pipeline diameter less than NPS 12);

(c) located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2 % of the pipeline's diameter (0.250 in. in depth for a pipeline diameter less than NPS 12);

(d) located anywhere on the pipeline with corrosion;

(e) dents of any depth that affect non-ductile welds such as acetylene girth welds or seam welds that are prone to brittle fracture;

(vi) maximum depth of metal loss feature including corrosion growth and tool tolerances predicted to be greater than 80%; and vii) a lamination that intersects a girth weld or seam weld, that lies on a plane inclined to the plane of the pipe surfaces, or that extends to the inside or outside surface of the pipe.

* For details, para 451.4 of ASME 31.4: "Repair Procedures for Steel Pipelines" may be referred.

(c) Monitored conditions

(a) patrolling of pipelines and associated facilities;

(b) maintenance of Right of User and inspection of Crossings;

(c) pipeline Cleaning Pigging;

(d) inspection of cathodic protection system; and

(e) Coating Survey (Closed Interval Potential Logging or Direct Current Voltage Gradient or ACVG or Pearson or Current Attenuation Test).

(i) process measures such as, Number of damages per excavation notification received;

(ii) operational measures such as, number of significant In-line Inspection anomalies; and

(iii) direct integrity measures such as, number of damages per km. of pipeline length.

(i) patrolling undertaken vs. Planned;

(ii) key Integrity issues such as encroachments, restoration, constructional deficiencies, mitigation plan and any operational issues;

(iii) the number of Integrity Management System required activities completed;

(iv) the number of defects found requiring repair or mitigation; and

(v) the number of leaks reported.

(i) the number of third-party damage events and near misses;

(ii) the number of pipeline hits by third parties due to lack of notification; and

(iii) aerial surveillance and patrolling reports.

(i) performance measures;

(ii) testing and inspection successes and failures;

(iii) new threat identification;

(iv) root causes analysis of pipeline breakdowns & accidents;

(v) process enhancement or changes (Management of Change);

(vi) recommended changes for the Integrity Management System;

(vii) additional training requirements necessary to support Integrity Management System;

(viii) public awareness program;

(ix) inspection tool performance (whenever applicable);

(x) inspection tool vendor performance;

(xi) alternative repair methods;

(xii) staffing for inspections, testing and repairs;

(xiii) past and present assessment results;

(xiv) data integration and risk assessment information;

(xv) additional preventive and mitigating actions;

(xvi) training needs of O&M personnel; and

(xvii) additional items as necessary to aid in the success of the IMP program.

(I) land owner and tenants along the Right of Use;

(II) general Public or Public institutions like schools, hospitals etc. near pipeline route;

(III) public officials and statuary bodies other than emergency responders; and

(IV) local and regional emergency responders.

(1) reason for change;

(2) authority for approving changes;

(3) analysis of implications (threat and risk analysis);

(4) documentation; and

(5) communication of change to affected parties.

(i) identifying and maintaining the documents required for Integrity management plan, procedures and records. This includes both controlled and uncontrolled documents;

(ii) defining Roles & responsibilities for implementation of program, documentation etc.;

(iii) reviewing of Integrity management plan and implementation of recommendation at predefined interval;

(iv) training and awareness of persons implementing the Integrity management plan;

(v) periodic internal Audit of integrity management plan and quality plan; and

(vi) documentation of corrective actions taken or required to be taken to improve the integrity management plan or quality plan.

Schedule 7

(i) who is responsible for each aspect of the asset and its management;

(ii) what policies and processes are in place to achieve targets and goals;

(iii) how they are implemented;

(iv) how performance is measured; and

(v) how the whole system is regularly reviewed and audited.

Schedule-8

Implementation Schedule Of Integrity Management System

Note: Steps for implementation to be followed as described in Schedule-7
* - For new pipelines, the above shall be complied within one year of date of commissioning

Schedule- 9

Review of The Integrity Mangement System

(i) IMS document is developed, approved and is valid;

(ii) activities are performed in accordance with the Integrity Management System;

(iii) verify if annual performance measures have been evaluated;

(iv) all action items or non-conformances are closed in a timely manner;

(v) the risk criteria used have been reviewed and documented; and

(vi) prevention, mitigation and repair criteria have been established, met and documented.

(a) Internal Audit - once in a year.

(b) External Audit - Once in every three years in-line with the approved IMS by third party empaneled by the Board.

Appendix-I

References

(1) Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for Petroleum and Petroleum products pipelines) Regulations, 2016;

(2) Petroleum and Natural Gas Regulatory Board (Codes of practices for Emergency Response and Disaster Management Plan) Regulations, 2010;

(3) ASME B31.4- Pipeline Transportation Systems for Liquid Hydrocarbons and other Liquids.

(4) ASME B31.8S - Managing System Integrity of Gas Pipelines;

(5) API 1160 - Managing System Integrity for Hazardous Liquid Pipelines;

(6) ASME B31Q - Pipeline Personnel Qualification;

(7) ASME B31G - Manual for Determining the Remaining Strength of Corroded Pipelines.

Appendix-II

Critical Activities Implementation Schedule

Appendix-III

Suggestive Chart for selection of Integrity Assessment OR Management Method* with respect to specific threat

* Some of the important Integrity Assessment or Management Methods have been mentioned in Schedule-5 of these regulations.
** Inline inspection frequency to be as per PNGRB (Technical Standards and Specifications including Safety Standards for Petroleum & Petroleum product Pipelines) Regulations, 2016