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Petroleum and Natural Gas Regulatory Board (Integrity Management System for Natural gas pipelines) Regulations, 2012

Published vide Notification No. F.No. Infra/IM/NGPL/12010, dated 5.11.2012

Last Updated 1st December, 2020 [act3746]

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

(b) "Board" means the Petroleum and Natural Gas Regulatory Board established under sub-section (1) of section 3 of the Act;

(c) "natural gas pipeline" means the pipeline as defined under the Petroleum and Natural Gas Regulatory Board (Authorizing Entities to Lay, Build, Operate or Expand Natural gas pipelines) Regulations, 2008;

(d) "operator" means an entity that operates natural gas pipeline network with the authorization of the Board;

[(e) "risk" means the measure of potential loss in terms of both the incident probability (likelihood) of occurrence and the magnitude of the consequences;]

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

[(h) "risk management" means an 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;]

(i) "spur-line" means a pipeline as defined in the Petroleum and Natural Gas Regulatory Board (Determining Capacity of Petroleum and Petroleum Products and Natural Gas Pipeline) Regulations, 2010;

[(ia) "transmission pipeline" means one or more segments of pipeline usually interconnected to form a network that transports gas from a gathering system, the outlet of a gas processing plant or a storage field to a high, medium or low-pressure pipeline system, a large-volume customer or another storage field;

(ib) "sub transmission pipeline" means a high-pressure pipeline connecting the main natural gas pipeline to the city gate station;]

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

(k) "right of [user](ROU) [***]" means the area or portion of land within which the pipeline operator or owner has acquired the right through the relevant provisions of law or in accordance with the agreement with the land owner or agency having jurisdiction over the land to lay and operate the natural gas pipelines;

(l) "integrated surveillance system" means the pipeline surveillance for third party encroachment activities along ROU. This may use optical fiber cable, microwaves and satellite as communication systems and could be integrated with SCADA's data;

[(m) "Shall" indicates that the provision in which it occurs is mandatory;

(n) "Should" indicates that the provision in which it occurs is recommendatory but not mandatory;]

(a) evaluate the risk associated with natural gas pipelines and effectively allocate resources for prevention, detection and mitigation activities;

(b) improve the safety of natural gas pipelines so as to protect the personnel, property, public and environment;

(c) have streamlined and effective operations to minimize the probability of Natural gas pipeline failure.

(i) the entity shall be required to complete each activity within the specified time limit 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 and make good all short comings within the time schedule. If the entity fails to complete such activities within the specified time schedule, relevant penal provisions of the Act shall apply];

(ii) 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. In case the entity fails to comply within the specified time, the relevant provisions of the Act and regulations shall apply.

Schedules

(see regulation 6)

Schedule-1

•   [Ensure] natural gas pipeline integrity in all areas which have potential for adverse consequences.

•   [Promote] a more rigorous and systematic management of natural gas pipeline integrity and mitigating the risk;

•   [Enhance] the general confidence of the public in the operation of natural gas pipeline.

•   [Enhance] the life of the natural gas pipeline with the inbuilt incident investigation and data collection including review by the entity.

Schedule-2

•  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, updation of data and reassessment of risk.

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

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

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

•  [Quality Plan]: This is the process to establish the requirements of quality in execution of the processes defined in the integrity management plan.

Note: These elements have further been detailed in Schedule-6.

Schedule-3

Schedule-4

[Schedule-5]

Integrity Assessment, Monitoring and Surveys

(a) Pre-assessment - determining feasibility of Direct 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 to these regulations.

(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 for all the entities involved to facilitate other entities to conduct studies or surveys and in implementation of 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 natural gas pipeline system; and

(iii) Aerial survey of Right of User at critical and in-accessible stretches for example hilly regions and Ghat sections and like other sections;

(i) Fiber Optics System;

(ii) Ground Sensor System;

(iii) Radar based detection system; and

(iv) Fence secure data access system.

Schedule-6

(I) Time Dependent Threats:

(1) External Corrosion

(2) Internal Corrosion

(3) Stress Corrosion Cracking

(II) Stable Threats:

(4) Manufacturing related defects

i. Defective pipe seam

ii. Defective pipe

(5) Welding /fabrication related

i. Defective pipe girth weld

ii. Defective fabrication weld

iii. Wrinkle bend or buckle

iv. Stripped threads /broken pipe /coupling failure

(6) Equipment

i. Gasket O-ring failure

ii. Control/relief equipment malfunction

iii. Seal pump packing failure

iv. Miscellaneous

(III) Time independent Threats:

(7) Third party /mechanical damage:

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

ii. Previously damaged pipe (delayed failure mode)

iii. Vandalism

(8) Incorrect operational procedure

(9) 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, 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, mud and landslides or muddy land effects; and

(v) High wind.]

•  Prioritization of pipeline sections/segments for scheduling integrity assessment and mitigation plan

•  Assessment of the benefits derived from mitigation actions

•  Determination of the most effective mitigation measures for the identified threats

•  Assessment of the integrity impact from modified inspection intervals

•  Assessment of the use of or need for alternative inspection methodology

•  More effective resource allocation

(a) Utilizing the services of Subject Matter Experts (SMEs)

(b) Relative Assessment Model

(c) Scenario -Based Model

(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 and/or mitigation option;

(e) They provide for a data feedback loop mechanism;

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

•  Increase in Operating Pressure, average temperature/dew point of gas, water content in gas beyond acceptable limits.

•  Changes in Right of Use conditions like development of encroachments, increase in third party activities/ population density, major washouts.

•  Pipeline Leak/rupture history.

•  Addition of new /expansion of the existing railway/road/waterway crossings.

•  Changes to pipeline cathodic protection levels due to external interference problems.

•  Any other issues which may affect the integrity of pipeline.

•  The results of previous integrity assessments.

[(i) Pressure testing;

(iv) Any other Integrity Assessment methodology.]

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

(i) Metal loss equal to or more than 80% of wall thickness.

(ii) Predicted failure pressure less than equal to 1.1 times the maximum allowable operating pressure (MAOP) as determined by ASME B31G or equivalent.

(iii) Metal loss indication affecting [***] longitudinal seam, if that seam was formed by direct current or low frequency electric resistance welding or by electric flash welding.

(iv) Any indication of adverse impact on the pipeline expected to cause immediate or near term leaks or ruptures based on their known or perceived effects on the strength of pipeline which include dents with gouges.

(v) Any near term failure indication.

(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:

(i) A plain dent that exceeds 6% of nominal pipeline diameter for pipeline operating at or above 30% of Specified Minimum Yield Strength (SMYS).

(ii) Mechanical damage with or without concurrent visible indentation of the pipe.

(iii) Dent with cracks.

(iv) Dent that affect ductile girth or seam welds if the depth is in excess of 2% of the nominal pipe diameter.

(v) Dents of any depth that affect non ductile welds.

* For more information on scheduled conditions, "Repair Procedures for Steel Pipelines" paragraph 851.4 of ASME 31.8 may be referred.

(c) Monitored conditions. - Monitored conditions show that defect will not fail before next inspection. Such indications are the least severe and will not require examination and evaluation until next scheduled integrity assessment [***] provided that they are not expected to grow to critical level prior to the next scheduled assessment.

(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

(e) Coating Survey (Closed Potential Logging/Direct Current Voltage Gradient/Pearson/Current Attenuation Test)

(i) Process measures e.g. Number of damages per excavation notification received

(ii) Operational measures e.g. Number of significant In-line Inspection anomalies

(iii) Direct integrity measures e.g. Number of damages per km. of pipeline length

•  Patrolling Inspected vs. Planned.

•  Key Integrity issues such as encroachments, restoration, constructional deficiencies, mitigation plan and any operational issues.

•  The number of Integrity Management System required activities completed.

•  The number of defects found requiring repair or mitigation.

•  The number of leaks reported.

•  The number of third party damage events and near misses.

•  The number of pipeline hits by third parties due to lack of notification.

•  Aerial surveillance and patrolling reports.

•  Performance measures.

•  Testing and inspection successes and failures.

•  New threat identification.

•  Root cause analysis of pipeline breakdowns and accidents.

•  Process enhancement / changes (Management of Change).

•  Recommended changes for the Integrity Management System.

•  Additional training requirements necessary to support Integrity Management System.

•  Public awareness programme.

•  Inspection tool performance (whenever applicable).

•  Inspection tool vendor performance.

•  Alternative repair methods.

•  Staffing for inspections, testing and repairs.

•  Past and present assessment results.

•  Data integration and risk assessment information.

•  Additional preventive and mitigating actions.

•  Training needs of O&M personnel.

•  Additional items as necessary to aid in the success of the IMP programme.

(I) Land owner and tenants along the Right of Use.

(II) General Public [or Public institutions like schools, hospitals or other like institutions] near pipeline route

(III) Public officials and statuary bodies other than emergency responders

(IV) Local and regional emergency responders

(i) Reason for Changes

(ii) Authority to approve changes

(iii) Analysis of implications (threat and risk analysis)

(iv) Documentation

(v) Communication of changes 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 and responsibilities for implementation of programme, 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.

(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.

•  Step#1: Prepared by In-house team or Consultant

•  Step#2: Checked by In-house team Head or Consultant head

•  Step#3: Provisionally approved by Head of Operation [or Maintenance of the entity]

•  Step#4: [Verification of Conformity] of IMS document with the Regulation by Third Party Inspection Agency (TPIA)

[•  Step#5: Approval of Integrity Management System document for implementation by the board of the entity for the first time and approval of subsequent periodic review by Chief Executive Officer (CEO) or Full -time Director of the entity.

•  Step#6: Approved IMS document along with confirmation from entity of its implementation shall be submitted to the Board.]

[Schedule-8]

Implementation Schedule of Integrity Management System:

Note: Steps for implementation to be followed as described in Schedule-7 to these regulations.

* For new pipelines, the period of 1 year shall be construed as one year from the date of commissioning of such pipelines.

[Schedule-9]

(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 - Every year;

(b) External Audit - Every 3 years in-line with the approved IMS by third party empaneled by the Board.

Schedule-10

Appendix-I

References

•  Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for Natural gas pipelines) Regulations, 2009;

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

•  ASME B31.8-Gas Transmission and Distribution Piping Systems;

•  ASME B31.8S - Managing System Integrity of Gas Pipelines;

•  ASME B31 Q- Pipeline Personnel Qualification

•  ASME B31G - Manual for Determining Remaining Strength of Corroded Pipelines.

Appendix-II

Critical Activities Implementation Schedule

[Appendix-III]

Suggestive Chart for Selection Of Integrity Assessment or Management Methods* With Respect To Specific Threat

* Some of the important Integrity Assessment or Management Methods have been mentioned in Schedule-5 to these regulations.

** Inline inspection frequency to be as per Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for natural gas pipelines) Regulations, 2009.

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