ARCHIVED - Maritimes and Northeast Pipeline Management Ltd. - Audit Report OF-Surv-OpAud-M124 01 - Appendix I: M&NP Integrity Management Program Audit Assessment Table
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M&NP Integrity Management Program Audit Assessment Table
- 1.0 Policy and Commitment
- 2.0 Planning
- 3.0 Implementation
- 4.0 Checking and Corrective Action
- 5.0 Management Review
1.0 POLICY AND COMMITMENT
1.1 Policy and Commitment Statements
Expectations: The company shall have a policy approved and endorsed by senior management (the Policy). It should include goals and objectives and commit to improving the performance of the company.
OPR-99 sections 4, 47 and 48
CSA Z662-07 Clauses 10.2.2 and 10.14
The Operator applies Maritimes and Northeast Pipeline’s (M&NP) Integrity Management Program (IMP) document, dated 31 March 2010 which includes Section 2: Corporate Policies, Objectives, and Organization. Subsection 2.1 contains a Policy and Objectives description of short term (1-4 year) and long term (5-10 year) plans for all integrity related program developments, including hazard identification, inspection and investigation and maintenance activities for all pipelines within the scope of the document. The IMP Policy is endorsed and approved by senior management. In addition, there is the Pipeline Integrity Oversight Committee (PIOC) with a mandate to administer the IMP for all Canadian regulated pipelines. PIOC committee members are comprised of senior management including: Director, Pipeline Integrity (Houston); Manager, Pipeline Design (Houston); Manager, Metallurgical Services (Houston); Director, Operations Compliance (Houston); Director, Facilities Operations (Houston); Director, Technical Operations (Southeast Region); and Director, Technical Operations (Northeast Region).
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has a policy which commits to continual improvement and is communicated throughout the organization.
Compliance Status: Compliant
 Each “Reference” in this table contains specific examples of the “legal requirements” applicable to each element but are not necessarily a complete list of all applicable legal requirements.
2.1 Hazards Identification, Risk Assessment and Control
Expectations: The company shall be able to demonstrate a procedure to identify all possible hazards. The company should assess the degree of risk associated with these hazards. The company should be able to support the rationale for including or excluding possible risks in regard to its environment, safety, integrity, crossings and awareness and emergency management and protection programs (management and protection programs). The company should be able to implement control measures to minimize or eliminate the risk.
OPR-99 sections 4(2), 39, 40, 41
CSA Z662-07 Clauses 10.2, 10.3.1.1(d), 10.14.1(a)(b), 16.2
Section 8: Hazard Identification and Control of M&NP’s IMP document, summarizes the hazards that are considered to be relevant to its operations. The identified hazards are used as input for a commercial risk assessment software program (RiskAnalyst) offered and administrated by Dynamic Risk Assessment Systems, Inc. M&NP has segmented its pipeline system into logical and logistical segments (valve to pressure reducing station (PRS) and PRS to end of line valve). This dynamic segmentation allows M&NP to calculate the risk values of individual segments and compare the overall risk of one segment to another. The hazards input into the program include: internal corrosion, external corrosion, stress corrosion cracking, manufacturing, construction, equipment, and weather-related and outside forces.
Section 8.3.2: Internal Corrosion of the IMP states that “All the natural gas pipeline systems operated by the Company are designed as dry gas systems and are monitored and maintained to prevent internal corrosion as described in the Company’s procedures. Thus internal corrosion is not considered a viable threat to the Company pipeline system at the current time.”
However, there was evidence based on in-line inspections (ILI) conducted in the past, that although the pipelines carry dry gas (5-7#/MMSCF) and are monitored for water and other potential corrodents, some pipelines had indications of internal anomalies. These pipelines included: Saint John PRS to Irving Refinery and the Saint John rural laterals, Point Tupper Lateral and the Moncton Lateral. Potentially, the most serious of these anomalies was in the Point Tupper Lateral with an ILI vendor call of 30% internal metal loss that was subsequently excavated and determined to be 23% internal metal loss. The Pipe and Coating Inspection Report (Form 7T-33AW dated 05/20/2009) indicated that “The anomaly assessed was an internal factory/manufacturer metal loss defect” and that moisture and the presence of corrodents was not a contributing factor to the internal corrosion identified. Regardless, M&NP assessed the anomaly using Modified B31G, Effective Area Method and the B31G method to determine the safe operating pressure as compared to the actual operating pressure.
In addition, the RiskAnalyst software produced internal corrosion output values that varied from 0.09 on the Moncton Lateral to 1.68 on Line 10 (Mainline). These values are on a scale of 1 to 10. Initially, these values were of concern as they represent a likelihood of failure due to internal corrosion. Upon examination of the Dynamic Risk Assessment Systems, Inc. algorithm in the IMP Section 2.4 Internal Corrosion, it was determined that the output values are a summary of all segments and of all algorithm outputs. While a detailed breakdown of individual segment and algorithm output values was not obtained, interviewees indicated that the scores resulted primarily from the Mitigation Multiplication Factor which uses the elapsed time since the last ILI, hydrostatic test or Internal Corrosion Direct Assessment. Thus, the numbers resulting from the software do not strictly represent a mechanistic probability of internal corrosion due to the presence of free water, acid gas (carbon dioxide/hydrogen sulfide) or microbiologically influenced corrosion. With respect to the software internal corrosion values that had a maximum of 1.68, this value is in the lower region of the corporate risk assessment matrix (Section 9: Risk Assessment, Figure 4: Risk Matrix) which has values bounded by 0.00 to 1.99. Thus the Operator considers the risk due to internal corrosion to be minimal.
The integrity management team has recognized the possibility of internal corrosion and has committed to implement a corrosion control program on all pipelines. The program would follow Standard Operating Procedure (SOP) Volume 2 - Corrosion, 2-3010 Internal Corrosion Monitoring and Mitigation which includes maintenance pigging and analysis of any deposits resulting from the pipeline pigging. The pigging program would have a targeted frequency of twice per year per pipeline segment, but ultimately the frequency for each pipeline would be assessment based. The integrity management team also indicated that, during the harmonization and revision of the IMP document, Section 8.3.2 Internal Corrosion would be revised from “internal corrosion is not considered a viable threat” to reflect that there is some evidence that internal corrosion should be considered, and thus mitigated. Based on the evidence presented to the Board during the audit, the Board is of the opinion that internal corrosion will be appropriately monitored and mitigated.
Based on documents reviewed and interviews, the Operator was able to demonstrate that it has a program to identify its hazards and associated risk, and mitigate the risk appropriately.
Compliance Status: Compliant
 Hazard: Source or situation with a potential for harm in terms of injury of ill health, damage to property, damage to workplace environment, or a combination of these. Risk: Combination of the likelihood and consequence(s) of a specified hazardous event occurring
2.2 Legal Requirements
Expectations: The company shall have a verifiable process for the identification and integration of legal requirements into its management and protection programs. The company should have a documented procedure to identify and resolve non-compliances as they relate to legal requirements which includes updating the management and protection programs as required.
OPR-99 sections 4, 6, 40 and 41(1)
CSA Z662-07 Clause 10.14
The M&NP Operations and Maintenance Specifications Manual (O&MSM), Section 00 Forward, recognizes the applicable pipeline codes and regulations (including the Canadian and US codes). The M&NP IMP document, Section 1.1 states “This Integrity Management Program has been developed in accordance with the guidelines of CSA Z662-07 Annex N and the Onshore Pipeline Regulations - 1999”. While CSA Z662-07 Annex N is not a mandatory requirement for pipelines regulated by the National Energy Board, voluntary adoption of its Guidelines for Integrity Management Programs provides a comprehensive framework for the M&NP IMP. The Operator has SOPs which describe in detail its IMP. The SOPs are being revised against all its applicable regulatory requirements and best practices.
Based on documents reviewed and interviews with staff, the Operator was able to demonstrate that it had identified its legal requirements and had integrated its regulatory obligations into the IMP.
Compliance Status: Compliant
2.3 Goals, Objectives and Targets
Expectations: The company should have goals, objectives and quantifiable targets relevant to the risks and hazards associated with the company’s facilities and activities (i.e., construction, operations and maintenance). The objectives and targets should be measurable and consistent with the Policy and legal requirements, and ideally include continual improvement and prevention initiatives, where appropriate.
OPR-99 sections 40, 47 and 48
CSA Z662-07 Clauses 10.2.2(h)(ii) and 10.14.1
The IMP, Section 2: Corporate Policies, Objectives and Organization, Subsection 2.1: Policies and Objectives, states that the pipeline integrity objectives are established as part of an ongoing process to develop short term (1-4 year) and long term (5-10 year) plans and budgets for all integrity-related program development, hazard identification, inspection and investigation, and maintenance activities for all pipelines included within the scope of this document.”
The IMP Section 2.3, Subsection 2.3.2: Performance Measures details M&NP’s Performance Plan which determines if the objectives of the IMP are being achieved and if pipeline integrity is being improved. Through collection and analysis of performance data collected semi-annually, the Operator can demonstrate that the IMP is being executed as planned. Performance Reports from 2006 to 2009 inclusive were reviewed and found to be in compliance with the expectations of the audit.
Based on documents reviewed and interviews, the Operator was able to demonstrate that it has goals, objectives and targets to continually improve upon its IMP.
Compliance Status: Compliant
3.1 Organizational Structure, Roles and Responsibilities
Expectations: The company shall have an organizational structure that allows its management and protection programs to effectively function. The company should have clear roles and responsibilities, which may include responsibilities for the development, implementation and management of the management and protection programs.
OPR-99 sections 40, 47 and 48
CSA Z662-07 Clauses 10.2.1, 10.2.2(b) and 10.14
The organizational structure, roles and responsibilities are detailed in several documents. The M&NP IMP, Section 2.2: IMP Administration and Responsibilities, Subsection 2.2.1: Pipeline Integrity Oversight Committee provides a high level outline of the functional relationships for the IMP.
The O&MSM, Section 00, Reference 05 also outlines the organizational structure of overall pipeline operation including management, field personnel and field staff and establishes the reporting relationship of all levels of staff, and the inter-relationship of all work functions.
Twelve organization charts were provided that delineated the organizational structure and reporting relationships, including specific roles and responsibilities for the IMP. Interviewees specifically responsible for the IMP provided a clear understanding of their responsibilities for the development, management and implementation of the various facets of the IMP.
Based on documents reviewed and interviews, the Operator was able to demonstrate that it has an organizational structure that allows it to implement its IMP appropriately and as designed.
Compliance Status: Compliant
3.2 Management of Change
Expectations: The company shall have a management of change program. The program should include:
- identification of changes that could affect the management and protection programs;
- documentation of the changes; and
- analysis of implications and effects of the changes, including introduction of new risks or hazards or legal requirements.
OPR-99 section 6
CSA Z662-07 Clause 10.2.2(g) )
The IMP, Section 6: Management of Change (MOC) addresses the requirements for the IMP and is intended to cover physical, procedural, technical and organizational changes that may impact the pipeline system. The MOC process describes in detail the types of changes that could be of impact to the pipeline system as well as the critical elements of change management. Section 6.3.1 of the IMP documents the MOC roles and responsibilities within the organization from a functional standpoint and includes an MOC process flow diagram describing the interrelationship between those roles and responsibilities.
Appendix 2 of the IMP contains the instructions for the Record of Change Form (Figure 6) with functional responsibilities and chronological sequencing of the procedures outlined in Annex N, Section N.8.1. While CSA Z662-07 Clause 10.2.2 (g) requires a (generic) MOC process, the Operator has voluntarily incorporated CSA Z662-07 Annex N, Sections N.8.1 and N.8.2 into its IMP which include more specific and detailed MOC requirements. On a more local level, the Operator’s Annual Corrosion Review Meeting identifies current items requiring change, determines the type of remedial actions required and follows-up/resolves integrity-related MOC issues.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has an effective MOC process to identify, document and analyze changes that could affect the IMP.
Compliance Status: Compliant
3.3 Training, Competence and Evaluation
Expectations: The company shall have a documented training program for employees and contractors related to the company’s management and protection programs. The company shall inform visitors to company maintenance sites of the practices and procedures to be followed. Training requirements should include information about program-specific policies. Training should include emergency preparedness and environmental response requirements as well as the potential consequences of not following the requirements. The company should determine the required levels of competency for employees and contractors. Training shall evaluate competency to ensure desired knowledge requirements have been met. Training programs should include record management procedures. The training program should include methods to ensure staff remains current in their required training. The program should include requirements and standards for addressing any identified non-compliances to the training requirement.
OPR-99 sections 4, 18, 29 and 46
CSA Z662-07 Clauses 10.2, 10.5 and 10.14
The IMP, Section 5: Competency and Training recognizes the increasingly complex nature of pipeline systems and the associated maintenance, inspection and monitoring requirements. The Operator also recognizes the need for personnel involved in the pipeline integrity program to possess highly specialized skills and that staff will be required to demonstrate competence in the areas for which they are responsible.
The Operator has classified personnel involved in the planning and execution of the IMP into General Service Providers and Critical Service Providers. The former consists of personnel involved in general activities and the latter consists of personnel involved in the execution of specialized pipeline inspection and maintenance activities. Technical competency requirements for both groups are based on an analysis of an individual’s present or expected involvement in basic or advanced aspects of the IMP activities. Following the analysis and assessment of basic training needs, the design and planning of training is conducted regularly, with training sessions scheduled no less than annually.
Training and qualifications for Critical Service Providers includes Operator staff, vendors and contractors. These training requirements include: ILI, engineering and risk assessments, non-destructive testing, stress corrosion cracking (SCC) and corrosion investigations, mechanical or materials defect assessments, pipeline defect repair, field recoating, hot tapping and maintenance welding. Where industry standards or certification are an applicable aspect in the qualification and evaluation of competency, the Operator includes these requirements for staff or contract personnel. Among these designations are: Professional Engineering Associations, Certified Engineering Technicians/Technologists, Non-Destructive Examination (NDE) service providers having CGSB Level II or III in MPI, UT or radiography and SCC.
The Operator’s management who are responsible for the IMP are required to provide relevant support for both the trainers and trainees with respect to equipment, software and opportunities to exercise the competencies. The audit program as outlined in Section 15.4 of the IMP ensures that the effectiveness of the training program and the objectives and expectations of the training program are being achieved. Documents and records of the completed training program for all staff are maintained in the local area offices.
Based on documents reviewed and interviews, the Operator was able to demonstrate that it has a training program for its staff and contractors as it relates to its IMP.
Compliance Status: Compliant
Expectations: The company should have an adequate, effective and documented communication process(es):
- to inform all persons associated with the company’s facilities and activities (interested persons) of its management and protection programs policies, goals, objectives and commitments;
- to inform and consult with interested persons about issues associated with its operations;
- to address communication from external stakeholders;
- for communicating the legal and other related requirements pertaining to the management and protection programs to interested persons; and
- to communicate the program’s roles and responsibilities to interested persons.
OPR-99 sections 4, 18, 28, 29, 40, 47 and 48
CSA Z662-07 Clauses 10.2.2(d) and 10.14
The IMP includes sections that document relevant aspects of its integrity programs. Examples of the most relevant of these to communication are: Section 1: IMP Scope; Section 2: Corporate Policies, Objectives and Organization; Subsection 188.8.131.52 Administrative/Technical/Regulatory Document Teams with eight tables outlining the functional roles and responsibilities; Subsection 2.3.2 Performance Measures; Section 3: Documentation and Information Methods; and Section 6: Management of Change Plan which includes Table 2: Responsibilities for Providing Approvals for Change and Section 11: Integrity Management Program Planning.
The IMP document, in addition to the SOP’s, provides sufficient detail to support the effective implementation of the IMP elements as well as ensuring that the inspection, measurement, monitoring and maintenance activities are conducted in accordance with the Operator’s specifications.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has effective communication to inform all interested persons of activities related to its IMP.
Although there are several internal and external mechanisms in place for communicating integrity issues, the Operator could not demonstrate that there is a formalized and implemented communication plan that outlines the distribution of various types of information to appropriate parties. While interviews confirmed communication is occurring throughout technical networks and through the means identified above, without a formal communication plan, the Operator cannot ensure that all stakeholders and interested parties are receiving the appropriate information in a timely fashion.
The Operator was able to demonstrate that it has adequate communication processes regarding integrity related information. The Board recommends that information related to the integrity of the system be included in a formalized communication plan.
Compliance Status: Compliant with recommendation
3.5 Documentation and Document Control
Expectations: The company should have documentation to describe the elements of its management and protection programs-where warranted. The documentation should be reviewed and revised at regular and planned intervals. Documents should be revised immediately where changes are required as a result of legal requirements or where failure to make immediate changes may result in negative consequences. The company should have procedures within its management and protection programs to control documentation and data as it relates to the risks identified in element 2.0.
OPR-99 sections 4, 27, 47, 48
CSA Z662-07 Clauses 10.2.2(e) and (f), 10.3.1.1(d) and 10.14.1
The Operator has recognized pigging as a hazard in its O&MSM (Section 04: Cleaning, Testing and Purging, Reference 05: Pipeline Pigging - General) where it clearly states that “Pigging is extremely dangerous when done incorrectly.” Item #3 in this document states “The pigging barrel is a pressure vessel. Operations involving opening of the door should be done with extreme care as the energy stored in high-pressure gas is sufficient to tear the door off its hinges and launch a pig out of the barrel at high velocity. Assurance that the barrel is fully vented is the pigging crew’s responsibility and is a major factor to their personal safety.”
SOP, Volume 1 - Pipeline, Procedure Number 1-5030 states “The following procedures for running pigs demonstrate general practices only; operating personnel shall develop and implement site specific procedures and thoroughly familiarize themselves with the requirements of these procedures prior to their use and operation.”
The site specific Cleaning Pig Procedure for the Halifax Lateral - Rural Section dated August 29, 2008 contains a detailed checklist procedure for launching and receiving pigs. The steps to be taken for receiving the pig are on pages 13 to 16 of this Pig Procedure. The labels given to some of the facilities (12” valving location, 2” pressure gauge access valves) referenced in the procedure are not accurately identified on the schematic. Also, the Nova Scotia Halifax Lateral schematic reviewed (PLDM&NCAN05.0) did not align with the rural pigging facilities (B-0708-4C) as built. A site tour of the Halifax rural receiver and urban launcher confirmed that the pigging facilities as constructed do not match the existing schematics. The type and location of these facilities could have significant impact on the procedures and ultimately the safety of operators performing the procedures, thereby necessitating accurate and current schematics.
The Draft Audit Report referred to “P&IDs (process and instrumentation drawings). In response to the Draft Audit Report, M&NP clarified that P&IDs are the original construction documents and thus may not be consistent with the current facility schematics and field labels. However, Board staff were in fact reviewing the PLDs that M&NP indicated are the official operating drawings. The nomenclature used was not the reason behind the finding of Non-Compliant with respect to this Element.
During the site tour, operations and maintenance personnel demonstrated a clear and complete understanding of the required receiving procedures, including: bringing the pig into the oversized barrel, ensuring that the pig’s location was in the oversized barrel versus the standard 12” piping using a compass which reacts to the magnetic pig tracking insert, isolating and blowing down the standard size (12”) upstream piping, switching analog pressure gauges to digital gauges to be able to detect very low pressures, removing the digital gauge and probing the gauge valve for obstructions to ensure full depressurization and finally opening the receiver door to extract the pig. However, these details are only reflected by one step in the written procedure as “Verify zero pressure in Receiver barrel on both sides of the pig (prior to opening the closure door).” Given the inherent hazards associated with receiving the pig, and the specific procedural details tailored to the unique piping and valving arrangements that may exist at each receiver, site specific written procedures are required. Relying only on “on-the-job training” is not sufficient to ensure adequate and effective training and competency of inexperienced personnel.
Review of the Pigging Training PowerPoint presentation provided (7/7/2010) (slides 51 to 58) illustrates the general pig receiving procedure. Every schematic contained in the presentation shows a pressure equalization line between the upstream inlet line and the oversized pig barrel. Although this is a desired facility design feature and is shown on the schematics in the employee training materials, the Halifax rural pig receiver does not include any such pressure equalization line. As well as the fact that employees are being trained on a procedure that relates to an equalization line that doesn’t currently exist, the absence of such a line increases the need for and importance of detailed procedures, such as indicated by the operations personnel during interviews, to absolutely ensure zero pressure on both sides of the pig.
Currently, pipeline pigging has been limited to initial cleaning runs and actual ILI pigging. In the future, as a result of the internal corrosion program to be implemented in 2011, more frequent pigging will be required on all mainlines and laterals. This increased exposure to operations personnel necessitates detailed, accurate and complete procedures for each pig launcher and receiver to identify site specific hazards and mitigate the risk associated with pipeline pigging.
The Operator could not demonstrate that it has a process to identify and revise changes to documentation where failure to make immediate changes may result in negative consequences.
Compliance Status: Non-Compliant
3.6 Operational Control - Normal Operations
Expectations: The company should establish and maintain a process to develop, implement and communicate mitigative, preventive and protective measures to address the risks and hazards identified in elements 2.0 and 3.0. The process should include measures to reduce or eliminate risks and hazards at their source, where appropriate.
OPR-99 sections 4, 27, 36, 37, 39 and 40
CSA Z662-07 Clause 10
The O&MSM contains numerous sections that address implementation of the technical requirements of OPR-99 section 36. These requirements include: maintaining communication facilities; periodic testing of instruments and equipment; continually recording suction and discharge pressures; marking the open and closed positions of critical valves; and posting signage along the boundaries of pipeline stations with critical contact information.
The IMP includes 15 Sections and 2 Appendices, and addresses the requirements of OPR-99 Section 27 which requires the development, regular review and updating of manuals to provide information and procedures to promote efficiency in the operation of the pipeline and facilities. The hazards identified in Section 8: Hazard Identification and Control and Section 9: Risk Assessment are effectively addressed in Section 10: Hazard Control and Risk Reduction; Section 12: Integrity Assessment Methods; Section 13: Inspections, Testing, Patrols and Monitoring and Section 14: Mitigation and Repair.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has a process to address the risks and hazards associated with its facilities and activities.
Compliance Status: Compliant
3.7 Operational Control - Upset or Abnormal Operating Conditions
Expectations: The company shall establish and maintain plans and procedures to identify the potential for upset or abnormal operating conditions, accidental releases, incidents and emergency situations. The company shall also define proposed responses to these events and prevent and mitigate the likely consequence and/or impacts of these events. The procedures must be periodically tested and reviewed and revised where appropriate (for example, after emergency events).
OPR-99 sections 4, 32, 37, 40 and 52
CSA Z662-07 Clauses 10.2, 10.3.2 and 10.14
The O&MSM Section 14, Reference 01: Contingency Plan is intended to provide communications and gas control operations for all pipeline facilities operated by the Operator. The communications systems are comprised of a wholly-owned and controlled satellite system to ensure ideal communication along the pipeline route. A 1-888 emergency telephone system has been put into place to be used by the public. The number is displayed on all M&NP line signs, valve sites, stations and related facilities. An after-hours answering service receives calls and communicates specific needs to the appropriate Operations Center or on-call technician.
As per CSA Z662-07 Clause 10.3.2.5, the Operator has made provisions for pre-tested pipe and related fittings to be stored at one or more of the Operation Centers or valve sites along the pipeline route for use in emergency repairs. Site visits confirmed the storage of pipe and fittings.
IMP Section 14, Reference 02 covers emergency and planned pipeline shutdown requirements and References 03 to 06 inclusive provide pipeline schematics with mainline valve identification.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has plans for upset or abnormal operating conditions. For more information related to the Operator’s Emergency Preparedness and Response (EPR) Plan as it relates to the requirements of OPR-99 please refer to Appendix IV: M&NP EPR Program Audit Evaluation Table.
Compliance Status: Compliant
4.0 CHECKING AND CORRECTIVE ACTION
4.1 Inspection, Measurement and Monitoring
Expectations: The company shall develop and implement surveillance and monitoring programs. These programs should address contract work being performed on behalf of the company. These programs should include qualitative and quantitative measures for evaluating the management and protection programs and should, at a minimum, address legal requirements as well as the risks identified as significant in elements 2.0 and 3.0. The company should integrate the surveillance and monitoring results with other data in risk assessments and performance measures, including proactive trend analyses. The company shall have documentation and records of its surveillance and monitoring programs.
OPR-99 sections 4, 27, 28, 36, 37, 39, 47, 48, 53(1) and 54(1)
CSA Z662-07 Clauses 9 and 10
The Operator’s IMP, Section 13: Inspection, Testing, Patrols and Monitoring outlines its procedures to conduct inspections, testing, patrols and monitoring in accordance with Clauses 9 and 10 of CSA Z662-07. The detailed procedures are contained in the SOPs. The SOPs have been “harmonized” to ensure the requirements for the U.S. and Canadian regulators are specified in terms of specific tasks and the frequencies of those tasks. The SOPs have been organized to address threat-specific requirements. For example, IMP Section 1.6: Inspection and Damage Prevention contains ten (10) procedures covering pipeline RoW patrols and leakage surveys. IMP Section 2.2: External Corrosion includes thirty (30) detailed procedures with the focus on cathodic protection inspection, testing and monitoring. Review of the Annual Cathodic Protection Survey Report for 2009 indicated that the survey scope (test points) and results (NACE criteria) met regulatory requirements.
CSA Z662-07 Clause 10.6.1.2 states that the frequency of pipeline patrolling shall be determined by considering such factors as: operating pressure, pipeline size, population density, etc., which are risk-based considerations. The Operator’s inclusion of risk-based frequencies as required by CSA Z662-07 is evident in SOP 1-6010 Pipeline Patrol and Leakage Survey Frequency Criteria, which specifies bi-weekly aerial RoW patrols.
To ensure the Operator has appropriate documentation and records of the inspection, surveillance and monitoring programs, each SOP contains links imbedded in the electronic document to the “Reporting” and “Forms” requirements upon completion of the SOP tasks.
In terms of data integration and analysis, IMP Section 13.2: Evaluation of Inspection, Testing, Patrol and Monitoring Results stipulates that, upon completion of each task, the results are evaluated to determine whether a potential threat exists, and when the results indicate the presence of conditions that might lead to a failure incident with significant consequences or to an external interference incident, an engineering assessment is to be performed in accordance with CSA Z662-07 Clause 10.14.
In terms of risk assessment, IMP Section 9.2.2: Review of Previous Integrity Management Processes states that information gained from integrity audits, performance metrics, integrity assessments and mitigative actions (i.e., Inspection, Testing, Patrols and Monitoring) over the previous year will be incorporated into the annual updating of the risk information for each threat.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has surveillance and monitoring programs to address its hazards and risks as it relates to the IMP.
Compliance Status: Compliant
4.2 Corrective and Preventive Actions
Expectations: The company shall have a process to investigate incidents or any non-compliance that may occur. The company shall have a process to mitigate any potential or actual issues arising from such incidents or non-compliances. Such mitigation may include appropriate timing and actions for addressing the issues that arise. The company shall demonstrate that it has established a documented procedure to:
- set criteria for non-compliance;
- identify the occurrence of any non-compliances;
- investigate the cause(s) of any non-compliances;
- develop corrective and/or preventive actions; and
- effectively implement the required corrective and/or preventive actions.
The company should develop procedures to analyze incident data in order to identify deficiencies and opportunities for improvement in its management and protection programs and procedures.
OPR-99 sections 4, 6 and 52
CSA Z662-07 Clauses 10.2.2(g) and (h), 10.3 and 10.14
The IMP, Section 7: Incident Investigations, details its requirements for incident reporting, on-site investigation, follow-up investigation and inclusions of any recommendations to the IMP that would reduce the likelihood of a recurrence of such an incident. Section 2.3.2: Performance Measures includes threatspecific incident data that would constitute non-compliances. The data is collected, monitored, reviewed and investigated by the PIOC on a semi-annual basis. An internal report is presented and reviewed by senior management as well as the integrity management staff of M&NP. While no incidents had occurred that required action for the Operator, the annual Corrosion Review Meeting has a standing agenda item of Review of Action Items, which addresses incident-related action items from previous years that are to be resolved. Although not an incident as per the NEB definition, the 2009 meeting recognized an inconsistency with respect to the O&M Manual criteria for cathodic protection versus the criteria of CGA OCC-1 and NACE International This issue was addressed and resolved.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has a process to investigate incidents and non-compliances.
Compliance Status: Compliant
4.3 Records Management
Expectations: The company shall establish and implement procedures to ensure that the records supporting the management and protection programs are retained, accessible and maintained. The company shall, as a minimum, retain all records for the minimum lengths of time as required by the applicable legislation, regulation and standards incorporated by reference into the regulation.
OPR-99 sections 4, 41 and 56
CSA Z662-07 Clauses 9.11, 10.2, 10.3, 10.4 and 10.14
The IMP, Section 4: Integrity Management Program Records, summarizes the Operator’s record management system whereby the records of integrity management activities and related operations and maintenance are maintained in many files and types of formats. These records are completed and retained as per the requirements of the individual related procedures. The records related to the pipeline design, construction, operation and maintenance are prepared, managed and maintained in accordance with the record retention rules. The types of records that are included in the records management program include:
- Pipeline design records;
- Materials standards and specifications;
- Material test reports;
- Joining and inspection records;
- Coating inspection records;
- Pressure test records;
- Pipeline environment records;
- Pipeline location records;
- Class location records;
- Cathodic protection records;
- Risk assessment records;
- Repair records; and
- Other records covering implementation and completion of risk mitigation activities.
An example of a record reviewed was the Annual Cathodic Protection Survey for 2009 which included all of the required data, including pipeline test points, inspection date, pipe-to-soil CP potential measurements and sign off by the technician.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has a records management program to ensure records are retained, accessible and maintained.
Compliance Status: Compliant
4.4 Internal Audit
Expectations: The company shall develop and implement a documented process to undertake audits of its management and protection programs and procedures. The audit process should identify and manage the training and competency requirements for staff carrying out the audits. These audits shall be conducted on a regular basis.
OPR-99 sections 4, 53 and 55
CSA Z662-07 Clauses 10.2.2(c) and (h)(iii)
The IMP, Section 15: IMP Review & Evaluation, Subsection 15.4 Audits, specifies that it will utilize both internal and external audits to formally validate and improve its IMP. While CSA Z662-07 Annex N is not specifically a requirement of the National Energy Board, the Operator has chosen to meet the requirements of Annex N.17.2(a) through (f) which include: audit scope and objectives; audit frequency and timing; responsibilities for managing and performing audits; auditor independence; auditor competency; and audit procedures. An external audit had been commissioned in 2007 by CC Technologies Canada, Ltd. which included in its scope Operations and Maintenance, Emergency Preparedness and Response, Environment, Health and Safety Program, Security Management Program, Training Program, Pipeline Integrity and the Safety and Loss Management System
The Operator has also committed to performing internal audits of its IMP on an annual basis as per Section 184.108.40.206 of the IMP document.
Based on documents reviewed and interviews conducted, the Operator was able to demonstrate that it has a process to undertake audits of its IMP.
Compliance Status: Compliant
5.0 MANAGEMENT REVIEW
Expectations: Senior management should formally review the management and protection programs for continuing suitability, adequacy and effectiveness. The review should be based on appropriate documentation and records including the results of the surveillance, monitoring and audit programs. This review should be formal and documented and should occur on a regular basis. The management review should include a review of any decisions, actions and commitments which relate to the improvement of the programs and the company’s overall performance.
OPR-99 sections 4, 40 and 55
CSA Z662-07 Clauses 10.2.2(h)(iii) and 10.14.1
See Appendix VII for the assessment of this element.
Compliance Status: See Appendix VII for the assessment of this element.
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