ARCHIVED - FAQs - Final Investigation Report: Trans Mountain Pipeline ULC Sumas Tank 121 Leak

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The NEB has investigated the cause of a release of crude oil into the secondary containment of Tank 121 at Trans Mountain Pipeline ULC’s (TMPU or the Company) Sumas Terminal in Abbotsford, B.C. on 24 January 2012. The full findings are available in the attached report.

Below, for your information, are some questions and answers
on the NEB’s investigation into the incident.

What caused the leak?

The NEB’s investigation revealed that the leak occurred after a gasket in a flange of the Tank 121 rook drain system failed under excessive pressure caused by water freezing in the roof drain system.

How much crude oil was released?

Approximately 90 m³ of crude oil was released within the secondary containment of Tank 121.

What immediate actions did the NEB take following the incident?

The National Energy Board was notified of the leak at 08:16 Pacific Standard Time on 24 January 2012. Soon after receiving the notification, the NEB’s Emergency Operations Centre (EOC) was activated. NEB staff were deployed and arrived on scene at 17:00 later that day.

The emergency phase of the incident was terminated at 12:50 on 25 January 2012 when the last free oil was removed from the secondary containment.

What were the impacts to people and the environment as a result of the incident?

No one was injured during the incident and the environmental consequences were limited to the contamination of the secondary containment gravel and air emissions. The secondary containment liner prevented the oil from migrating further.

Air monitoring was conducted throughout the response. TMPU personnel were assigned to monitor air quality adjacent to the containment area as well as around the perimeter of the Sumas Terminal. TMPU personnel also delivered written notices to approximately 100 residents in the surrounding area.

A community ambient air monitoring program with both monitoring and sampling components was conducted by a specialized consultant at eight locations close to residential areas and an elementary school.

At the close of the incident phase on 25 January 2012, NEB staff determined there were no further threats to people or the environment after the initial impacts.

In addition to the immediate cause of the leak, the Board also noted the following findings as contributing factors to the incident:

  1. The practice of keeping the roof drain valves normally open was a contributing factor to the incident.
  2. The process that TMPU used to manage the change to the normal roof drain valve position was inadequate because it did not have a requirement for ensuring that the change would be communicated to field personnel, who were directly affected by such a change. In addition, the fact that TMPU’s field personnel were not informed of the new procedure is a non-compliance with the OPR-99 section 28.
  3. The night shift control centre operator (CCO) failed to follow TMPU’s procedures by not setting the creep alarm on the Legacy System within 15 minutes of completing the receipt of crude oil in Tank 121. The fact that the CCO did not follow TMPU’s procedures is a non-compliance with the OPR-99 subsection 4(2).
  4. The night shift CCO failed to recognize the possible leak situation when viewing the Tank 121 volume trend.
  5. The night shift CCO failed to follow TMPU’s procedures by not having a field technician investigate on site the creep alarms which could not be explained by normal operations. The fact that the CCO did not follow TMPU’s procedures is a non-compliance under the OPR-99 subsection 4(2).
  6. The threshold value for the creep alarm on the Test System was not set at the proper value. This information was not known by the night shift CCO and it may have contributed to the inappropriate response from the night shift CCO to the creep alarms.

Why were these findings of concern to the Board?

The NEB investigation revealed that many factors contributed to this incident. The release of 90 m³ of crude oil in the secondary containment of Tank 121 may have been avoided or minimized if TMPU had ensured that its change to the drain valve normal position procedure had been effectively implemented and if the leak had been detected earlier.

The NEB also found that if appropriate action had been taken while setting and responding to the SCADA system alarms, the leak could have been detected earlier.

The NEB expects its regulated companies to anticipate, prevent, manage and mitigate potentially dangerous conditions associated with its pipelines. As part of this, the Board expects pipeline companies to continually improve in the areas of safety, security and environmental protection. They must also promote a positive safety culture as a part of their management system.

What corrective actions has the Board required TMPU to take as a result of the findings in this report?

The Board will require TMPU to take the following actions as a result of its findings into this incident.

  • Revise its General Operating Procedures 2.2.4 Winterization of External Floating Roof Drain Systems to require that the external nozzle and roof drain valve be heat traced and insulated in locations where high winter rainfall makes other winterization methods impractical;
  • Implement a new procedure that all roof drain valves operate in the normally closed position and require operations staff to monitor the draining of water from the roof and if any oil were to be detected, the drain valve would be immediately closed;
  • Revise its Facility Modification Request change management procedure to require a work order to be issued to ensure direct communication to affected personnel when a critical procedural change has been approved;
  • Review the use of the Legacy System as the basis for operation of the system and the process for commissioning and testing the Test System (the new SCADA system) with all CCO’s, paying specific attention to the requirement and actions for tank alarms;
  • Ensure timely and accurate diagnosis in the future through formal communication with CCOs as well as revisions to Procedure 2.2.3.5: Unexpected Tank Level Deviation;
  • Undertake a review of creep alarms to determine the frequency of false alarms caused by roof oscillation;
  • Install a petroleum gas detection sensor on a trial basis at one of the secondary containment sumps at the Sumas terminal to confirm the ability of this equipment to augment the existing oil detection equipment; and
  • Modify the creep alarm threshold values in the Test System for all of TMPU’s tanks so that they correspond to 10 m³ volume deviations and threshold values are no longer set manually by the CCO’s.

TMPU has identified corrective actions to address all of the findings of cause and contributing factors indentified in this investigation report.

The NEB will continue to conduct targeted compliance verification activities with TMPU in order to verify that their corrective actions have been adequately implemented.

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