Administrative Monetary Penalty – Westcoast Energy Inc, carrying on business as Spectra Energy Transmission – AMP-002-2020

Administrative Monetary Penalty – Westcoast Energy Inc, carrying on business as Spectra Energy Transmission – AMP-002-2020 [PDF 451 KB]

NOTICE OF VIOLATION

REFERENCE NUMBER: AMP-002-2020

Information for Pipeline Company/Third Party/Individuals

On October 9, 2018 (date violation was detected)

Westcoast Energy Inc.

Was observed to be in violation of a CER regulatory requirement. This violation is subject to an administrative monetary penalty, as outlined below.

Section One – Violation Details

Section Two – Relevant Facts

Briefly describe reasonable grounds to believe a violation has occurred

Westcoast Energy Inc. (Westcoast), which operates as Spectra Energy Transmission (a wholly owned subsidiary of Enbridge Inc. (Enbridge) following Enbridge’s merger with Spectra in February 2017), owns and operates a 36" (914.4 mm) natural gas transmission pipeline (hereinafter referred to as NPS 36 L2) pursuant to Certificate of Public Convenience and Necessity GC-32, as amended.  Westcoast also owns and operates a 30" (762 mm) natural gas transmission pipeline (hereinafter referred to as NPS 30 L1) pursuant to Board of Transport Commissioners for Canada Order 86329, which shares the vast majority of the same right of way with NPS 36 L2.  Additionally, the NPS 36 L2 and NPS 30 L1 pipelines share the same right of way as a Pembina Pipeline Corporation (hereinafter referred to as Pembina) 12 inch liquids (oil) pipeline, the latter of which is regulated by the BC Oil & Gas Commission. 

On 9 October 2018, there was a rupture and subsequent fire/explosion (hereinafter referred to as the Incident) on Westcoast’s NPS 36 L2 pipeline located approximately 13km northeast of Prince George, BC (INC2018-142).  The Incident occurred at segment 4AL2 of NPS 36 L2, which is located between compressor stations 4A (upstream of Incident) and 4B (downstream of Incident).  As a result of the rupture on NPS 36 L2 pipeline, a parallel section of the NPS 30 L1 was vented during a controlled blowdown.  As such, both the NPS 36 L2 pipeline and the adjacent NPS 30 L1 pipeline segment, between compressor stations 4A and 4B, were depressurized. To ensure immediate safety, an Inspection Officer Order (IOO) NB-001-2018, as amended, was issued to Westcoast on 10 October 2018 to limit the operating pressure on the NPS 36 L2 pipeline, between station 2 to the Huntingdon meter station, and on the NPS 30 L1 pipeline, segment 4AL1 (between Compressor Station 4A and Compressor Station 4B). Both Westcoast pipelines were back to normal operations by November 2019.

The NPS 36 L2 pipeline, which was put into service in the 1960s, had a maximum operating pressure of 6,453 kPa, as approved by the National Energy Board (NEB).  At the time of the Incident, the operating pressures at compressor station 4A discharge and compressor station 4B suction were 6,357 kPa (922 psig) and 5,660 kPa (821 psig), respectively.

The Transportation Safety Board (TSB) conducted an investigation into the rupture; it released its report on 4 March 2020.  As set out in the TSB report, the rupture originated at stress corrosion cracks on the outside surface of the NPS 36 L2 pipeline.

Following the rupture, the NEB conducted regulatory oversight activities and an enforcement investigation. During these processes, the NEB determined that Westcoast did not adequately implement its integrity management program with respect to stress corrosion cracking and inspection practices and that, had Westcoast done so, the pipeline defect could have been detected to avoid the rupture. 

Therefore, it has been determined that Westcoast violated subsection 4(2) of the Canadian Energy Regulator Onshore Pipeline Regulations, which states:

“Without limiting the generality of subsection (1), the company shall ensure that the pipeline is designed, constructed, operated or abandoned in accordance with the design, specifications, programs, manuals, procedures, measures and plans developed and implemented by the company in accordance with these Regulations”

*Note: On 28 August 2019, the National Energy Board Act was repealed and replaced by the Canadian Energy Regulator Act, and the National Energy Board was replaced by the Canada Energy Regulator (CER).

**On 1 April 2020, the Miscellaneous Program made non-substantial amendments to National Energy Board’s Onshore Pipeline Regulations, including changing the name to the Canadian Energy Regulator Onshore Pipeline Regulations.

Background:
The Incident of 9 October 2018 took place in a relatively remote location, and although nobody was injured, nearby residents, including the Lheidli T’enneh First Nation, evacuated as a precaution. Environmental damage did occur as a result of the Incident; specifically, the Incident resulted in damage to vegetation (forest and grass) on provincial Crown land surrounding the Incident site. Additionally a portion of the adjacent oil pipeline owned and operated by Pembina was damaged during the Incident and required replacement.

The area affected by the fire that resulted from the pipeline rupture covered roughly 52 000 m2. Approximately 3.98 million cubic metres of natural gas from the NPS 36 L2 pipeline was combusted and an additional 0.85 million cubic metres of natural gas was vented during a controlled blowdown of a parallel section of the NPS 30 L1 pipeline.  There was also a crater, approximately 10 m wide and 30 m long, that was created as a result of the explosion. The Pembina pipeline was not flowing at the time of the rupture.

In response to the Incident, the NEB activated its Emergency Operation Centre in Calgary, Alberta, and NEB staff were deployed to site.  To ensure immediate safety, an Inspection Officer Order (IOO) NB-001-2018, as amended, was issued to Westcoast on 10 October 2018 to limit the operating pressure on the Westcoast NPS 36 L2 pipeline, between station 2 to the Huntingdon meter station, and on the adjacent Westcoast NPS 30 L1 pipeline, segment 4AL1. On 23 October 2018, the initial IOO was amended to extend the pressure restriction to the entire NPS 36 L2 pipeline.  On 30 November 2018, the NEB issued a Notice of Measures Satisfied allowing the NPS 30 L1 pipeline segment 4AL1 to return to service.  Additionally, by 28 November 2019, all specified measures of the IOO NB-001-2018, as amended, were satisfied and the NPS 36 L2 pipeline was able to return to full operating pressure.

In order to obtain more information from Westcoast regarding the cause of the Incident and corrective actions taken, the NEB/CER sent Information Requests (IRs) to Westcoast on 19 November 2018 (IR#1), 24 July 2019 (IR#2), 29 October 2019 (IR#3) and 12 June 2020 (follow up to IR #3). Westcoast provided its responses to the NEB/CER on 17 and 21 December 2018, 23 August 2019, 30 October 2019 and 19 June 2020, respectively.

Frequency of In-line Inspections:

On 21 December 2018, in its response to IR #1, Part C&D, Westcoast provided Table 19-5 which states that a stress corrosion cracking (SCC) In Line Inspection (ILI) of the NPS 36 L2 pipeline’s segments is to be performed at an interval of 5 to 9 years.  On 23 August 2019, in its response to IR #2, Westcoast provided the In Line Inspection Tracker spreadsheet for the NPS 36 L2 pipeline segment 4AL2 titled “Attachment1-1 ILI Inspection Tracker 4AL2” (hereinafter referred to as the Inspection Spreadsheet). The Inspection Spreadsheet indicated that a proposed ILI interval was a maximum of 9 years for the NPS 36 L2 pipeline segment 4AL2. Specifically the Inspection Spreadsheet stated: “Proposed ILI Interval (max 9 years)” and a “Calculated Inspection Frequency” of 9 years. 

Additionally, on 30 October 2019 Westcoast provided the CER with its Stress Corrosion Cracking Hazard Management Plan (dated 2017-10-30). As indicated in its IR response #2, Westcoast’s SCC ILI uses EMAT technology (ElectroMagnetic Acoustic Transducer). EMAT is commonly used by gas operators for the detection of SCC. In its SCC Hazard Management Plan, the company indicated in its IR response #2 that re-inspection intervals are determined primarily based on the “as found” size of stress corrosion cracking features upon excavation. The growth rate used to determine re-inspection frequency on segment 4AL2 of the NPS 36 L2 pipeline was based on dig results from the 2003 EMAT inspection on the 4AL2 segment. At the time, a factor of safety was applied, resulting in the re-inspection interval with a maximum of 9 years.

On 19 June 2020, in its response to follow up IR #3, Westcoast confirmed that the SCC ILI re-inspection frequencies of 5 to 9 years shown in Table 19-5 in response to IR#1 was presented as a summary of calculated results using the process described in the SCC Hazard Management Plan. Specifically, Westcoast stated “as the SCC Hazard Management Plan specifies that a ‘maximum re-inspection interval between successive EMAT inspections of ten years is required’, the calculated re-inspection frequency of 5-9 years could be extended by one year.”  Based on the above, an SCC ILI for segment 4AL2 of the NPS 36 L2 pipeline was required between 5 to 9 years, but the EMAT ILI could be extended by one year.

Extension of In-Line Inspection Intervals:

As noted above, Westcoast’s response to IR #3 confirms that the calculated re-inspection intervals of 5 to 9 years could be extended by one year. Table 19-5 of Westcoast’s response to IR #1 states that based on stress corrosion cracking growth rate, largest detected feature, and tool technology advancement, an extension of 1 year could be allowed with a technical assessment to justify the extension.

Information regarding the technical assessment is found in section 4 of Westcoast’s Standard Operating Practice (SOP) Waivers and Technical Assessment 1.8, which was filed as part of its response to IR #2. The SOP states:

“The SOP Waiver and Technical Assessment form shall be used for a process, decision or work activity that is required under the Pipeline Integrity Management Program and which is;

1. a deviation from an existing clause of an integrity management SOP, Plan, or Program (e.g. delay of a feature inspection beyond the planned time)”

The SOP Waiver and Technical Assessment required a multi-step process. As part of this assessment, Westcoast was required, among other things, to consider safety.  Based on the above, Westcoast could extend its SCC ILI interval by one year for segment 4AL2 of the NPS 36 L2 pipeline if a SOP Waiver and Technical Assessment was conducted as per its Integrity Management Program.

Westcoast’s Inspections of NPS 36 L2 pipeline segment 4AL2

Table 19-1 in Westcoast’s response to IR #1, notes that the last SCC ILI for the NPS 36 L2 pipeline was conducted on 30 July 2008 and before that on 22 July 2003. Westcoast also indicated it had done pipeline replacement/repair on sections of the NPS 36 L2 pipeline between compressor stations 4A and 4B at five locations between 1985 to 2014.

Westcoast notes that an EMAT ILI was scheduled for segment 4AL2 of the NPS 36 L2 pipeline for October 2018, however the SCC ILI had not been performed by the time of the Incident. Regardless, this SCC ILI would not have occurred within the maximum of 9 years from the previous SCC ILI which was performed on 30 July 2008.  As an SCC ILI on segment 4AL2 of the NPS 36 L2 pipeline was not performed within the maximum 9 year period as indicated in Westcoast’s Inspection Spreadsheet, the NEB requested Westcoast provide its technical assessment justifying the one year extension of the ILI frequency as per its SOP.

In its IR #2 response, Westcoast indicated that:

“Westcoast is unable to locate a technical assessment and waiver form for the extension of the inspection interval by one year for the 4AL2 pipeline segment. No evidence exists that a request to perform an inspection deferral assessment was made in 2017 for the EMAT ILI of the 4AL2 segment…Westcoast is unable to locate any documented internal communications pertaining to the decision to extend the ILI interval for the EMAT ILI tool on the 4AL2 segment by one year.”
As per its SOP 1.8, Westcoast was required to complete a technical assessment and waiver form for an extension beyond the maximum of 9 years.  There is no evidence that Westcoast completed a technical assessment as required by its SOP 1.8 which forms part of its Integrity Management Program.

Conclusion:

Pursuant to subsection 4(2) of the Canadian Energy Regulator Onshore Pipeline Regulations, a company shall ensure that the pipeline is designed, constructed, operated or abandoned in accordance with the design, specifications, programs, manuals, procedures, measures and plans developed and implemented by the company in accordance with these Regulations.

Westcoast’s Inspection Spreadsheet establishes that, based on calculated results using the process described in the SCC Hazard Management Plan, inspections for the NPS 36 L2 pipeline segment 4AL2 were to occur within a maximum of 9 years. A one year extension of the ILI interval was possible if a technical assessment had been completed pursuant to Westcoast’s Standard Operating Practice Waivers and Technical Assessment 1.8, which forms part of Westcoast’s Integrity Management Program. 

Westcoast provided evidence in Table 19-1, which formed part of its response to IR #1, that the last SCC ILI for the NPS 36 L2 pipeline was conducted on 30 July 2008. Westcoast was unable to provide any evidence to show that a technical assessment, as required by the SOP 1.8, was undertaken prior to making a decision to extend the SCC ILI interval on segment 4AL2 of the NPS 36 L2 pipeline by one year.

Westcoast indicated that an EMAT ILI was scheduled for segment 4AL2 of the 36 NPS L4 pipeline for October 2018, however the SCC ILI had not been performed by the time of the Incident. Regardless, this SCC ILI would not have occurred by 2017, which was the 9 year maximum from the previous SCC ILI, performed on 30 July 2008. While Westcoast’s SOP 1.8 allowed for a one year extension following a technical assessment, Westcoast has been unable to find evidence that said technical assessment was undertaken or completed.  Had an SCC ILI been performed as per Westcoast SCC Hazard Management Plan and the corresponding Inspection Spreadsheet during the required 5 to 9 year inspection interval, the inspection tool likely may have captured the stress corrosion cracking that failed on the NPS 36 L2 pipeline segment 4AL2. Alternatively, had a technical assessment been conducted as per Westcoast’s SOP 1.8, the technical assessment may have raised concerns with the extension of the SCC ILI beyond the 9 year maximum period, and Westcoast could have taken the necessary steps, based on the findings of the technical assessment, to ultimately prevent the Incident on the NPS 36 L2 pipeline segment 4AL2.

The NEB/CER investigation has determined that the immediate cause of the failure of NPS 36 L2 pipeline segment was due to stress corrosion cracking which could have been detected, and thus the rupture would likely have been prevented, had an SCC ILI occurred within the maximum 9 year period. Alternatively, if Westcoast was proposing to extend the inspection interval by one year, it was required to complete a technical assessment as per its Standard Operating Procedures 1.8. 

Westcoast has been unable to provide evidence to show that either were done as required by Westcoast’s Integrity Management Program. This AMP is being issued due to the company’s failure to conduct its SCC ILI within the required period and implement its Standard Operating Practice Waivers and Technical Assessment, as required by its Integrity Management Program. Specifically, Westcoast did not implement its established procedures for identifying and managing changes required to defer the stress corrosion cracking inspections.

Section Three – Penalty Calculation

A) Baseline Penalty (Gravity Level = 0)

Refer to AMP Regulations, Subsection 4(1)

B) Applicable Gravity Value

Refer to AMP Regulations,, Subsection 4(2))

Notes to explain decision to apply multiple daily penalties, or “Not Applicable”
N/A

Section Four – Total Penalty Amount

Section Five – Due Date

(30 days from receipt of Notice of Violation)

Original signed by
Keith Landra

Designated Officer
Administrative Monetary Penalties

Notes

You have the right to make a request for a review of the amount of the penalty or the facts of the violation, or both, within 30 days after the Notice of Violation was received.

If you do not pay the penalty nor request a review within the prescribed period you are considered to have committed the violation and you are liable for the penalty set out in the Notice of Violation. The penalty is due on the date indicated above.

The unpaid penalty amount is a debt due to the Crown and may be recovered by collection procedures stipulated in the Financial Administration Act.

The information regarding the violation may be posted on the CER website:

• a) 30 days from the date this Notice of Violation was received; or
• b) upon issuing a decision following a Request for Review.

To Make Payment:

You may remit your fee payment by Electronic Funds Transfer (EFT) or by cheque payable to the order of Receiver General for Canada.

EFT payments can be arranged by contacting the Director of Financial Services, Monday to Friday, from 09:00 to 16:00 Mountain Time:

• Telephone: 403-919-4743 / 800 899-1265
  Fax: 403-292-5503 / 877-288-8803

Cheques should be made out to the *Receiver General for Canada" and mailed to:

• Canada Energy Regulator
  Attention: Finance
  Suite 210, 517 – 10th Avenue SW
  Calgary, Alberta T2R OA8

Your completed Payment form should be enclosed with your payment.

Date modified:

2022-08-05