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Enbridge Northern Gateway Project Joint Review Panel

gatewaypanel.review-examen.gc.ca

5 Public safety and risk management

Contents

5 Public safety and risk management

5.1 Engineering design overview

5.2 Hydraulic design

5.3 Route selection process

5.4 Tunnel design and construction

5.5 Pipeline design

5.5.1 Pipeline design and installation within the Clore and Hoult tunnels

5.5.2 Corrosion control measures

5.5.3 Pipe toughness

5.6 The Kitimat Terminal

5.6.1 Structural design of the tanks

5.6.2 Secondary containment

5.7 Pump stations

5.8 Mainline valves and valve locations

5.9 Joining and non-destructive examination

5.9.1 Non-destructive examination of final tie-in welds

5.9.2 Radiographer and ultrasonic technicians

5.9.3 Pressure testing

5.10 Leak detection

5.10.1 Leak detection system operations

5.10.2 Leak detection methods

5.11 Corrosiveness of dilbit

5.12 Risk approach

5.12.1 Semi-quantitative risk assessment

5.12.2 Internal corrosion control

5.12.3 External corrosion control

5.12.4 Third party damage

5.12.5 Material and manufacturing defects

5.12.6 Construction defects (welding and installation)

5.12.7 Incorrect operations

5.12.8 Equipment failure

5.12.9 Geohazards

5.13 Post-construction monitoring and inspections

5.13.1 Integrity management

5.13.1.1 Pipeline integrity

5.13.1.2 Facilities integrity

5 Public safety and risk management

The Panel assessed the proposed project design and operations to determine whether the project would be constructed and operated in a safe, reliable, and environmentally responsible manner. A number of engineering and operational topics and issues were examined during the Panel's process. These included the suitability of the route, hydraulic design, station and terminal design, use of risk-based design, geohazards, seismic design, materials, integrity management, pipeline control, and leak detection systems.

5.1 Engineering design overview

Northern Gateway committed to designing and constructing its project to meet or exceed all applicable regulations, codes, and standards. Northern Gateway said that it benefitted from the knowledge and experience gained from other projects, and incorporated the lessons learned into its own designs. It said that innovations in engineering, technology, construction methods, and material improvements also contributed to an overall safer and more reliable design. Some intervenors said that detailed design information should be provided before any Panel recommendation on the project.

Northern Gateway said that the engineering information it provided in relation to design and construction, which is preliminary in nature, exceeds the level of information submitted for other projects, in some respects. Northern Gateway said that it deferred final decisions regarding certain aspects of the project's design, construction, and operations to the detailed engineering phase of the project, when the detailed information required for these final decisions would be available.

Views of the Panel

Final designs require a greater level of detail about the project's precise route and the geotechnical conditions along it than is currently available at this stage of the project. The Panel finds that Northern Gateway has presented a level of engineering design information that meets or exceeds regulatory requirements for a thorough and comprehensive review, in terms of whether or not it can construct and operate this project in a safe and responsible manner that protects people and the environment. The Panel has set out conditions that the National Energy Board would enforce to provide continued oversight during final engineering design.

The Panel expects Northern Gateway to continue to follow good engineering practice. This consists of applying informed judgement and proven and accepted engineering methods, procedures, and practices to address a technical problem. The application of good engineering practice results in an appropriate, cost-effective solution that meets the needs of the project, meets regulatory requirements, and protects the safety of persons, the environment, and property, when the solution is properly implemented and maintained. Where there are potential unknowns that are difficult to predict accurately due to natural variability, the Panel finds that a precautionary approach is needed in applying good engineering practice.

5.2 Hydraulic design

The project's oil pipeline is designed to transport four different low vapour pressure (LVP) crude types: conventional oil, synthetic crude oil, bitumen blended with condensate, and bitumen blended with synthetic crude oil. The proposed condensate pipeline would transport a single comingled condensate commodity. Because the oil pipeline would operate as a batched pipeline, the hydraulic analysis assumed that dilbit, the hydrocarbon with the highest viscosity, would govern its flow rate.

The goal of a pipeline's hydraulic design is to optimize facilities in order to minimize construction and operating costs. This involves considering a number of factors, such as fluid properties, pressure, temperature, pipe diameter, steel grades and wall thicknesses, pump facility locations and capacities, the required flow, and economic factors.

Among the concepts that Northern Gateway evaluated in the initial design stages were:

  • transporting dilbit versus a heated and insulated bitumen pipeline;
  • system design pressures from 1,440 to 2,160 pounds per square inch gauge (psig); and
  • route alternatives in the coastal mountain area to reduce pumping requirements and associated power costs.

Northern Gateway's target annual average capacity for the oil pipeline in 100 per cent dilbit service is 83,400 cubic metres (525,000 barrels) per day. It said that a potential expansion of the annual average capacity of up to 135,100 cubic metres (850,000 barrels) per day was part of the engineering design for this pipeline. Northern Gateway referred to this volume as the pipeline's ultimate capacity. Both of these capacities represent 90 per cent of the pipeline's theoretical design capacities of the pipeline and would allow for normal maintenance and construction activities that reduce pipeline flow.

Northern Gateway said that the condensate pipeline's target average capacity is 30,700 cubic metres (193,000 barrels) per day with an ultimate capacity of 43,700 cubic metres (275,000 barrels) per day.

Northern Gateway would be required to file subsequent applications with the National Energy Board, should it wish to increase the oil pipeline's volume capacity above 83,400 cubic metres (525,000 barrels) per day or the condensate pipeline's annual average capacity above 30,700 cubic metres (193,000 barrels) per day.

Northern Gateway selected the optimal diameter size for the oil and condensate pipelines using a parametric cost of service analysis which considered various diameter and number of station options, and determined the optimal pipeline size for a given flow. The cost of capital, and operating and maintenance costs, were calculated for these flow rates. Northern Gateway eliminated some design options because they exceeded Enbridge's maximum pipe velocity limitation of 3 metres (10 feet) per second. Other options were eliminated because the velocity at initial flow rates was too low and would not maintain the turbulent flow needed for batching operations.

Views of the Panel

For new pipelines, it is prudent for companies to consider the ultimate capacity at the project design stage. Typically, pipeline construction affects the environment to a greater extent than pump station construction, and having the ability to increase capacity economically by only adding pump stations has merit.

The Panel finds that Northern Gateway followed good engineering practice by optimizing the pipeline hydraulic design using a parametric cost of service analysis and ensuring that turbulent flow is maintained. Turbulent flow permits batching operations and reduces the potential for sedimentation issues within the oil pipeline. The Panel accepts that the chosen design may be expanded to accommodate some future growth by adding pumping facilities. This approach would minimize the potential footprint associated with hydrocarbon transportation infrastructure between Alberta and Kitimat.

5.3 Route selection process

The Panel reviewed the appropriateness of the applied-for general pipeline route under Issues 9 and 10 of the List of Issues (Appendix 5), which address the criteria that Northern Gateway used to select the proposed 1-kilometre-wide general route corridor, and the proposed facilities' general locations. Pipeline routing criteria are discussed in Chapter 8.

In its application, Northern Gateway identified a preferred 25-metre-wide permanent pipeline right-of-way, plus associated temporary workspace within the corridor. The Panel explained that, while it may consider evidence and submissions regarding potential effects associated with the preferred 25-metre-wide right-of-way and associated temporary workspace, it is not within the Panel's mandate to approve the specific, detailed pipeline route or facility locations.

Northern Gateway would be required to apply separately to the National Energy Board for subsequent approval of the detailed route, if the project is approved. It must prepare plans, profiles, and books of reference (PPBoR) that describe the precise location of the pipeline right-of-way in relation to the land it crosses. It must make the plans, profiles, and books of reference available for public viewing and must serve notice on directly-affected landowners, as well as publish notices in local newspapers. Under the National Energy Board Act, the National Energy Board would establish a separate regulatory process to review the proposed detailed route.

Northern Gateway provided a list of criteria that it considered in evaluating various alternatives for the pipeline route during the preliminary design stage. Northern Gateway said that each alternative was reviewed by its Route Review Committee, consisting of engineering, geotechnical, construction, and environmental specialists, which made decisions on a consensus basis. Northern Gateway said that its route selection process is ongoing and involves consultation, as well as technical and geotechnical field work.

Northern Gateway said that one of the challenges in determining a route through the Coast Mountains was pipeline constructability and operability in very steep and rugged terrain. It evaluated a number of alternative segments through this area and selected a route with 2 tunnels, each approximately 6.5 kilometres long, between the Clore River and Hoult Creek valleys. Northern Gateway said that the tunnels allowed it to:

  • eliminate the need to construct and operate the pipelines at high elevations;
  • significantly reduce potential constructability and operability issues;
  • locate the pipelines at lower elevations resulting in reduced hydraulic pumping needs; and
  • propose a significantly shorter route that avoids numerous watercourse crossings, sensitive alpine terrain, and potential geohazards.

The Panel notes that the route filed as part of the May 2010 project application was referred to as Route Revision R, whereas the route considered throughout most of the Panel's process was Route Revision U. On 28 December 2012, Northern Gateway filed Route Revision V, which included five pipeline route and four pump station relocations. Northern Gateway said that these revisions were in response to input received during Aboriginal and public consultations. It said that it was considering an additional relocation in the Burns Lake area of British Columbia, but decided not to propose it since it depended on further engagement with the relevant Aboriginal groups.

Northern Gateway said that it would finalize the detailed pipeline route within the 1-kilometre-wide pipeline corridor during detailed engineering. The detailed route would incorporate detailed engineering, construction, and operations considerations; further site-specific constraint mapping; results of Aboriginal Traditional Knowledge studies; and further field investigations. It would also incorporate input from participating Aboriginal groups, communities, landowners, the public and other interested parties, and government authorities.

Various intervenors said that it was challenging to access and understand details related to ongoing route revisions. One intervenor questioned the Route Revision V filing timing, as it was after the evidentiary hearing's portion on construction and engineering had taken place.

The Fort St. James Sustainability Group questioned the proposed location of the pump station near Pitka Creek, south of Fort St. James. It recommended that Northern Gateway relocate the station further away from the creek. Reasons given included concerns about noise, effects on wildlife habitat loss, and the potential for leaks that may contaminate the local aquifer.

Regarding the Fort St. James pump station, Northern Gateway said that it considered, but did not accept, alternate locations east and west of the proposed location. It said that the proposed location is adjacent to year-round road access that is important for this type of facility. It also noted that the location is adjacent to a high voltage power line, which is tentatively slated for an upgrade that would accommodate the station's power requirements. Because of these factors, the potential footprint for access and power supply was minimized. Northern Gateway said that ground conditions are favourable at the proposed location and there do not appear to be any environmentally-sensitive areas at or adjacent to the site.

Northern Gateway said that, within the hydraulic design constraints, locations to the west of the proposed site were found to be either closer to occupied properties, in environmentally-sensitive areas, or in more geotechnically-challenging areas. Locations to the east were either closer to occupied properties adjacent to the airport, in closer proximity to the Stuart River, or in more geotechnically-challenging areas.

Views of the Panel

The Panel finds that Northern Gateway followed good engineering practice in determining a route that avoids or minimizes exposure to geohazards (e.g., unstable slopes), reduces pumping requirements, and provides a safe and responsible route for construction and operations. Northern Gateway used a Route Review Committee, comprised of an internal team of engineering, geotechnical, construction, and environmental specialists, to determine the proposed corridor. The Panel finds that this multi-disciplinary committee, which used a consensus-based decision-making process, was an acceptable approach to developing the initial corridor both prior to and through Northern Gateway's consultation on the project.

The Panel finds that Northern Gateway's route selection process, route selection criteria, and level of detail were appropriate for the project. The Panel recognizes that, in some situations, such as locating the Fort St. James pump station, the outcome of the route selection process did not produce the desired end result for some parties.

The Panel heard concerns about Northern Gateway's process for deciding where to re-route and the fact that revisions were ongoing. Northern Gateway's submitted route revisions reflect new information obtained from ongoing consultation with affected parties, as well as changes that address environmental or geohazard concerns. The Panel finds that its process provided a venue for interested parties to question Northern Gateway on its route and notes that Northern Gateway made amendments to its application as the process proceeded. The Panel is satisfied that intervenors had an appropriate opportunity to question Northern Gateway and comment on these changes in their final argument.

5.4 Tunnel design and construction

The pipeline route segment between the upper reaches of the Clore River and Hoult Creek would cross a section of the Coast Mountains unbroken by low elevation passes. Northern Gateway proposed 2 tunnels, each approximately 6.5 kilometres long, to avoid construction, environmental, and operating risks associated with a conventional pipeline route on steep slopes. Northern Gateway's 2009 preliminary geotechnical report (revised in 2010) examined the geology and anticipated geotechnical conditions for the tunnels.

The geological assessment was based on a field investigation program consisting of geological mapping, core drilling, and geophysics. The field-mapping and drilling program included identifying rock types, estimating rock strength, and characterizing geological structures and discontinuities. Geological and engineering geology profiles were created for the tunnel alignments based on information collected. Rock mass properties for the main rock types along the tunnel alignments were developed and used to estimate tunneling conditions.

Northern Gateway's feasibility assessment considered slope hazards, portal locations, engineering geology, tunneling conditions, tunnel construction, and pipeline design and installation. In addition, tunnel and surface site investigation field work took place in October 2012. This consisted of portal site visits to visually assess the suitability of the proposed tunnel portal locations, geological mapping visits to visually assess geological units along proposed tunnel alignments, and access road and surface works visits to visually assess surface soil units and terrain (e.g., slopes, creeks, and instability). Three individuals representing two different Aboriginal groups participated in these site visits and field work.

Northern Gateway convened an external review panel of international tunneling experts to look at a number of scenarios, particularly with respect to the potential for difficult tunneling in portal areas and in fault zones. That panel concluded that the means exist to safely construct the Clore and Hoult tunnels.

Northern Gateway provided conceptual cross-sectional drawings for the tunnels indicating that each would be approximately 6.8 metres in diameter (Figures 5.1 and 5.2). The tunnels would either be circular or inverted U-shaped, depending on the tunneling method used (bored, or drill and blast). Other preliminary concepts that Northern Gateway presented included:

  • permanent infrastructure to provide road access for inspection and maintenance to all tunnel portals;
  • lighting and ventilation for inspection and maintenance;
  • power supply by either dedicated service line or on-site generator;
  • a maintenance building for maintenance equipment and material storage;
  • safety systems for tunnel monitoring that are designed to meet project requirements, and that would be connected to the Enbridge Edmonton pipeline operations control centre through remote communications to provide real-time monitoring;
  • monitoring sensors to detect vibration, temperature, fire, and gas; and
  • closing tunnel portal doors during normal operations to prevent unauthorized entry.

Northern Gateway said that it would develop further details about tunnel design and construction during detailed engineering.

The Office of the Wet'suwet'en raised questions about the camp and staging site, and the waste rock dump site. Concerns were related to potential effects from metal leaching and acid rock drainage in Wet'suwet'en territory and on their natural resources. It was also concerned that the volume of potentially acid generating rock is not known.

During the Panel's process, Northern Gateway's experts answered questions about the predicted tunnel waste rock volume, the potential storage space required, and the disposal of sulphide-bearing rock. These experts estimated the volume of in-situ rock from the tunnels at 350,000 cubic metres (plus or minus), assuming an approximately 13,000-metre combined length, a 7-metre width, and a 7-metre height. The locations of the disposal areas are illustrated in Figure 5.5. They also estimated a bulking factor of 30 to 40 per cent, representing 455,000 to 490,000 cubic metres of waste rock. The waste rock volume would depend on the tunnel construction method. Waste disposal fills would be approximately 6 to 8 metres high and would be contoured with the landscape. Regarding sulphide-bearing rock disposal, Northern Gateway's experts expect to segregate sulphide-bearing materials and use established techniques and design principles from the mining industry, such as encapsulation and containment. Another option may be dilution using limestone, depending on the amount of sulphide-bearing materials encountered.

Figure 5.1 Conceptual Drill and Blast Tunnel

Figure 5.1 Conceptual Drill and Blast Tunnel

Figure 5.2 Conceptual Bored Tunnel

Figure 5.2 Conceptual Bored Tunnel

Views of the Panel

The Panel heard evidence of a preliminary nature regarding construction of the Clore and Hoult tunnels. Northern Gateway would determine the final design of the tunnels during detailed engineering. The Panel requires Northern Gateway, before constructing the tunnels, to obtain further information on rock mass quality, groundwater conditions, mitigation measures for groundwater and potential sulphide-bearing rock, confined space entry procedures, final cross-sectional drawings, and the tunnel construction plans.

The Panel is of the view that Northern Gateway may have under-estimated the waste rock bulking factor given the rock type classifications in the preliminary geotechnical report for the tunnels and potential alignment changes. The Panel requires Northern Gateway, before constructing the tunnels, to develop final details on the location, size, and design of waste rock disposal. Provisions within the National Energy Board Act would allow Northern Gateway to apply for National Energy Board approval of amendments to its disposal locations, if necessary.

5.5 Pipeline design

Northern Gateway said that its approach to selecting pipeline wall thickness and pressure design is to ensure a flat maximum operating pressure (MOP) head profile (with an emphasis on the maximum operating pressure head profile expressed in terms of metres or feet of crude, and not a flat maximum operating pressure profile expressed in kilopascals or pounds per square inch). Northern Gateway reasoned that a flat maximum operating pressure head profile would reduce the risk of pipeline overpressure in the event of a downstream blockage. It said that this approach also results in a design where the maximum station discharge pressure is the only pressure control set-point that is necessary to protect the pipeline from overpressure under steady state conditions between two consecutive pump stations. This is illustrated in Figures 5.3 and 5.4 for both the oil and condensate pipelines.

Implementing this design approach means that locations along the pipeline route with elevations lower than that of the upstream pump station require a higher design pressure (thicker-walled pipe). Locations with elevations higher than that of the upstream station require a lower design pressure (thinner-walled pipe). This relationship is due to the static head of the fluid column in a pipeline during zero-flow conditions, resulting in higher pipeline pressures in low-lying areas, and lower pipeline pressures at high points. Northern Gateway said that, during detailed engineering, any pipeline wall thickness changes along the route would be balanced with the additional required manufacturing, logistical, and construction considerations. It said that it would validate the design by conducting transient analyses where it would analyze various abnormal conditions to ensure the pipelines can withstand the operating pressures that may result.

Northern Gateway's application contained wall thicknesses for both the oil and condensate pipelines that were fully compliant with the Canadian Standards Association (CSA) Z662-11 pipeline standard and the design philosophy described above. Northern Gateway said that it decided to increase the wall thickness and operate the pipeline at a lower stress level in response to feedback from the public and Aboriginal groups about the sensitivity and the special habitats the pipeline would cross.

Northern Gateway said that this design approach, which is a conventional stress-based approach, is consistent with industry standards, National Energy Board Act regulations, CSA Z662-11, as well as Enbridge Engineering Standards, which embed a risk-based approach.

The Enbridge Engineering Standards require pipe design to consider the effect of resultant longitudinal, axial bending, torsional, and hoop stresses, in addition to the stress interactions and reactions on the pipeline system. Typical loads considered during design include:

  • internal pressure;
  • thermal expansion and contraction;
  • differential movements;
  • self-weight of the pipe, contents, and gravity loads;
  • static wind loads and static fluid loads;
  • external hydrostatic pressure;
  • buoyancy effects;
  • geotechnical loads, such as slope failures and other soil movements;
  • cyclic loads;
  • external live loads (e.g., overburden, vehicles);
  • dynamic or seismic loads; and
  • ice loads.

Northern Gateway said that there may be specific locations along the pipeline route where strain-based design would be used in accordance with Annex C of CSA Z662-11. These locations would be determined during detailed engineering. It said that it would consider geography, geology, soil type, service loading, and operational design parameters to conservatively predict the stresses and strains that the pipelines may experience.

Northern Gateway would also consider stresses associated with pipeline construction. It said that it would consult engineering experts for pipeline segments predicted to experience soil instability, such as upheaval forces, consolidation, forces due to loading by soil movement, and seismic forces and soil strains. These experts would have expertise in pipeline stress and strain and, in consultation with geotechnical, hydrological, welding, and materials experts, may recommend alternative stress mitigation strategies to reduce the in-service strain to a suitable level.

Northern Gateway said that it would develop a stress and strain monitoring methodology for the pipelines, tailored specifically to each pipeline segment. It said that available technologies include internal inspection tools incorporating an inertial navigation system, sometimes referred to as a GEOPIG™. Other technologies use instrumentation mounted directly on the pipeline to monitor pipeline strain, or installed within a slope or other geohazard area to monitor ground movement.

Views of the Panel

The Panel finds that Northern Gateway's proposed pipeline engineering design meets or exceeds the minimum requirements of the National Energy Board Onshore Pipeline Regulations, which incorporate CSA Z662-11 requirements.

The Panel is satisfied with Northern Gateway's design approach to achieve a flat maximum operating head profile to reduce the risk of overpressure incidents that could occur from equipment failure or incorrect operations. In the design that Northern Gateway provided near the end of the Panel's process, there were localized instances where the objective of designing for a flat maximum operating head profile was not achieved with the pipe wall thicknesses specified. The Panel requires Northern Gateway to have the pipeline maximum head profile be greater than or equal to the discharge head of the upstream pump station. Where that is not possible, the Panel requires Northern Gateway to develop design and operational measures that reduce or eliminate the risk of pipeline overpressure (i.e., that the pressure could exceed the maximum operating pressure established by the National Energy Board). Northern Gateway said that it would achieve this requirement by incorporating mechanical overpressure protection into its design, where necessary.

Northern Gateway would use a conventional stress-based design together with a strain-based design, where circumstances require it. Northern Gateway said that it would monitor the actual amount of stress and strain on the pipelines, as well as other hazards, using a number of methods, including in-line inspection (ILI) tools. The Panel requires Northern Gateway to monitor the amount of stress and strain on the pipelines, particularly for sections where it used strain-based design. The Panel requires Northern Gateway to prepare a report summarizing the loading and dynamic effects that the pipelines may experience and that verifies adequate pipeline strength. This report must also identify and address potential pipe deformation that may impede in-line inspection tool passage.

As a precautionary measure, the Panel requires Northern Gateway to verify the fracture toughness of the weld metal and heat affected zones of pipe fabrication welds, where strain-based design is used. Instances of low toughness in these areas may affect the integrity of the weld or base metal during strain-induced pipe deformation.

5.5.1 Pipeline design and installation within the Clore and Hoult tunnels

Northern Gateway said that many aspects of pipeline design and installation within the tunnels would be finalized during detailed engineering. This includes workspace requirements, staging areas, construction procedures, supports, anchors and rollers (for moving pipe through the tunnels), and pipe stress analysis. It said that a critical requirement of the tunnel lining and ground support system would be to protect the pipelines from potential rock fall hazards originating from the tunnel crown.

Northern Gateway anticipated that pipeline installation in the tunnels would use a staged approach. It said that tunnel line pipe segments would be assembled, welded, coated, and tested outside of the tunnels, creating strings up to 240 metres long at pipe staging areas at one of each tunnel's portals. This would be done using standard pipeline construction equipment during the last stages of tunnel excavation. Northern Gateway said that it has identified potential staging areas at the east portal of the Clore tunnel and the west portal of the Hoult tunnel.

Northern Gateway said that, during pipe installation, it would move pipe strings to a roller-based launch frame at each staging area portal. A cable and winch system would then pull the pipe strings into the tunnels. The lead end of each successive pipe string would be welded to the trailing end of the pipe already in the tunnels. Coating and testing would be completed at the portal before the pipe string is advanced. During installation, rollers would support the pipe along the full tunnel length. Northern Gateway would establish the final, optimal pipeline placement during detailed engineering.

Based on recent European experience with a 48-inch gas transmission pipeline in the Sorenberg Tunnel in Switzerland, Northern Gateway said that its proposed pipelines would be permanently supported on concrete or steel pipe supports fixed to the tunnel floor. It would design pipe supports for long-term operations. Straps on the pipe supports would provide lateral restraint. It would select support spacing to meet pipe deflection criteria. Northern Gateway would install an anchor block at the centre of each tunnel to isolate pipe expansion. It would also install expansion loop pipe and induction bends in individual segments, which it would weld in place to accommodate thermal and stress-induced pipe expansion. Tie-ins for tunnel line pipe with expansion loop pipe would also be completed in place. The work inside the tunnels would use some specialized construction equipment suitably sized to work within the confined space.

Figure 5.3 Condensate Pipeline Hydraulic Gradient (Route Revision V)

Figure 5.3 Condensate Pipeline Hydraulic Gradient (Route Revision V)

Figure 5.4 Oil Pipeline Hydraulic Gradient (Route Revision V)

Figure 5.4 Oil Pipeline Hydraulic Gradient (Route Revision V)

Views of the Panel

Oil and gas pipelines currently operate in long tunnels in Europe and South America, and in shorter tunnels in Canada. Based on the evidence that other larger pipelines have been successfully built and operated in tunnels, and Northern Gateway's preliminary descriptions of its pipeline installation in the tunnels, the Panel finds that pipeline construction and operations within the proposed tunnels is feasible. Construction methods to be used would differ from standard pipeline procedures and may create unique issues. As a result, the Panel requires Northern Gateway to develop further details on how it would construct the pipeline segments within the tunnels, including details about welding, non-destructive examination, protective coatings, and pressure testing.

5.5.2 Corrosion control measures

Northern Gateway said that the oil and condensate pipelines would be coated with fusion bond epoxy applied at a coating plant. It said that, during detailed engineering, it would evaluate a three-layer High Performance Composite Coating system for use on either a portion or the entire length of the pipelines. Northern Gateway said that the High Performance Composite Coating system would be comprised of fusion bond epoxy, adhesive, and polyethylene layers. Horizontal directionally-drilled or bored pipeline sections would have an additional abrasion-resistant coating. It said that it would also use rock shield, sand padding, wooden lagging, or concrete coating, where needed during construction, to provide additional protection for the pipe coating. Coating costs would make up approximately 3 to 5 per cent of the total construction costs.

Northern Gateway said that fusion bond epoxy, used extensively by Enbridge on large diameter pipeline projects, would be the key layer in terms of preventing corrosion on the proposed pipelines. It said that advantages of fusion bond epoxy, relative to High Performance Composite Coating, include lower material and installation costs, and easier weld-coating in the field.

It said that advantages of a High Performance Composite Coating, where required, relative to fusion bond epoxy, include:

  • better resistance to corrosion and cathodic disbondment in highly-corrosive environments such as acid rock drainage;
  • higher resistance to damage during transportation, handling, and backfilling;
  • higher resistance to damage in rugged terrain and trench conditions;
  • better long-term resistance to ultra-violet degradation; and
  • overall cost savings compared to additional protective measures required where fusion bond epoxy coating is damaged under conditions such as those listed above.

Northern Gateway said that decisions on coating would incorporate Enbridge's detailed coating standards. It would work with coating producers, coating applicators, and construction personnel during detailed engineering to select the appropriate coating system for each location.

In its review of the project, Natural Resources Canada said that the approaches proposed by Enbridge to control external corrosion by using protective coatings are appropriate and consistent with current industry best practices. It said that High Performance Composite Coating is more widely used in Europe than in North America. It was of the view that more widespread use in North America would increase pipeline integrity and safety.

Northern Gateway said that, for the oil and condensate pipelines, cathodic protection (CP) is a secondary corrosion control measure in support of the protective coating. The pipeline cathodic protection system would be designed and installed in accordance with applicable codes and regulations and Enbridge's engineering standards and specifications. Ongoing cathodic protection monitoring would be in accordance with CSA Z662-11 and Canadian Gas Association (CGA) Standard OCC-1-2005. The pipelines would be electrically isolated from the pump stations so that the available pipeline cathodic protection current remains with the pipelines. The cathodic protection system would be designed to connect to the local power grid. Northern Gateway said that there are two major classes of cathodic protection systems – remote rectifier bed and distributed anode – and that the choice of system would depend on the soil conditions at a given location.

In response to questions about cathodic protection effectiveness in different soil conditions, including permafrost, Northern Gateway said that it measured rectifier voltage and amperage on an ongoing basis, but that it typically recorded readings on a monthly basis since the change between incremental readings was typically quite small. It then used recorded data to determine the requirement for ground bed maintenance or replacement, or for installing new equipment.

Regarding the potential for pipeline coating disbondment due to cathodic overprotection (applying too much voltage to a pipeline), Northern Gateway said that this would be unlikely to happen because it followed well-known practices. It said that, if such damage occurred, annual surveys or regular in-line inspections would detect it.

In response to the Panel's potential condition to require a three-layer or High Performance Composite Coating for the entire length of both pipelines, Northern Gateway said that such a requirement would result in an uneconomic design that would add no value in most instances. Northern Gateway said that it would be best to work with coating producers and applicators, and with construction personnel during detailed engineering, to select the appropriate coating for each location.

The Samson Cree Nation and Ermineskin Cree Nation said that both pipelines should be coated for their entire length with a three-layer or other high performance coating to decrease the likelihood of a spill resulting from external corrosion.

C.J. Peter Associates Engineering said that the National Energy Board should determine the coating specifications for strength, resistance to cracking, and other properties, as well as field repair methods and non-destructive examination under the coating and of the coating itself.

In reply argument, Northern Gateway said that the estimated incremental cost of requiring a 3-layer coating for the entire length of both pipelines was approximately $50 million. It said that Enbridge has experience with three-layer and fusion-bond epoxy coatings on its various systems and is familiar with the advantages of each system. It said that fusion-bond epoxy is well-suited to the soils along the route in Alberta, and it expected engineering assessments to confirm that it would be an appropriate coating from Bruderheim to kilometre post (KP) 600. Northern Gateway said that, while detailed engineering had yet to be done, it expected engineering assessments to confirm that a 3-layer coating system would be appropriate in the rocky terrain from approximately KP 600 to KP 800, and KP 900 to KP 1177.

Figure 5.5 Proposed Tunnel Locations

Tunnels through two mountains would avoid numerous watercourse crossings, sensitive alpine terrain, and potential geohazards.

Figure 5.5 Proposed Tunnel Locations

Views of the Panel

External corrosion is a frequent cause of pipeline leaks and ruptures. The Panel finds that pipeline coating is the principle measure to prevent external corrosion. To ensure that there are no gaps in protection, the condition of the coating is checked before the pipe is lowered into the trench. Coating damage may occur during the lowering and backfilling processes. In light of the consequences of a pipeline failure, it is imperative to protect the coating during the construction process, or to have it be sufficiently resistant to damage from stones that may hit the pipe. Northern Gateway said that it would use appropriate mitigation, such as sand padding or rock shield, in areas of rocky terrain.

The Panel accepts Northern Gateway's evidence that the benefits of High Performance Composite Coating include better resistance to corrosion and cathodic disbondment in highly-corrosive environments, and higher resistance to damage in rugged terrain and from rough handling. These are desirable traits for this project.

Despite the additional cost, the Panel requires Northern Gateway to use a three-layer or High Performance Composite Coating for the oil and condensate pipelines from KP 600 to the Kitimat Terminal. The Panel finds that flexibility is needed in situations where another coating is expected to provide superior protection, such as for directional drilling where abrasion resistance may be paramount.

Field welds must be protected from external corrosion by field-applied coatings that are compatible with the factory-applied coating. The Panel requires Northern Gateway to file its field-applied coating and application specifications. This requirement would facilitate inspections during construction.

The Panel requires Northern Gateway to verify the integrity of the pipeline coating after construction to determine whether it was damaged during the lowering and backfilling processes.

The Panel is satisfied with Northern Gateway's proposed approach for designing, installing, monitoring, and maintaining its cathodic protection systems and composite coatings in order to achieve safe and responsible pipeline operations.

5.5.3 Pipe toughness

Northern Gateway said that it would specify CSA Category I pipe for the oil and condensate pipelines because both pipelines were classified as low vapour pressure pipelines. It would specify CSA Category II pipe during detailed engineering for locations, if any, where it determines air testing to be the preferred test method. It said that Category II pipe may be installed at aerial crossings, in the two proposed tunnels, and in areas with potential geotechnical hazards or seismic activity. It said that, while it may consider using Category II pipe as an additional safeguard in geotechnically-hazardous or seismic areas, this may not be necessary from a fracture initiation perspective. It said that, although it may specify Category I pipe, it expected this material to have a sufficient degree of toughness from a fracture initiation perspective, given modern pipeline steelmaking practices.

Northern Gateway said that the notch toughness requirements would be based on a high percentage (typically 90 per cent) of the flow stress dependent criteria. Northern Gateway said that this approach has been applied and accepted on other major pipeline projects. Its preliminary calculations, using the Battelle fracture initiation model, suggested that critical through-wall defect lengths would be in excess of 100 millimetres for all pipe thicknesses it is currently considering. Its preliminary calculations also indicate that a through-wall defect with a length of approximately 50 millimetres can be sustained with Charpy V-notch absorbed energy values of less than 10 Joules.

Northern Gateway said that proven notch toughness properties are not required for Category I pipe. It said that Category II pipe is distinguished from Category III pipe because it requires both Charpy V-notch toughness testing and a drop weight tear test, while Category III pipe requires only Charpy V-notch toughness testing. The drop weight tear test is for a full-thickness specimen, unlike the Charpy test, which has a fracture surface area of no more than 10 by 8 millimetres. Northern Gateway said that, with the oil pipeline's specified thicknesses, current research in drop weight tear test results suggests that a great deal of variability in the shear area results could occur. Northern Gateway was concerned that, if Category II pipe was required, there was a possibility of introducing some manufacturing risk on the pipeline suppliers. It said that the drop weight test's only purpose was to guard against long propagating fractures, which do not occur on liquid pipelines.

C.J. Peter Associates Engineering said that Northern Gateway should specify CSA Category II pipe because it had the most stringent toughness requirements. It argued that Northern Gateway's own evidence indicates that at least 10 Joules would be sufficient to sustain a 50-millimetre-long through-wall defect, which suggests that, instead of no toughness requirements for Category I pipe, a Charpy V-notch test is required to determine the pipe body toughness. C.J. Peter compared the proposed pipelines' toughness requirements to those that the American Pipeline and Hazardous Materials Safety Administration (PHMSA) specified for the Keystone XL pipeline (40 Joules). It argued that, since the project involves more northerly pipelines that would experience colder temperatures, Northern Gateway should be even more conservative in its specification.

Views of the Panel

The proposed pipelines would transport low vapour pressure products and the CSA Z662-11 code allows Northern Gateway to specify Category I pipe. Category I pipe has no proven notch toughness requirements. Northern Gateway's evidence indicates that a minimum fracture initiation toughness value is required and that Charpy V-notch testing can determine if the pipe has the required toughness.

The Panel does not approve the use of Category I pipe for this project. The Panel requires Northern Gateway to specify Category III pipe, as a minimum, for the oil and condensate pipelines, which would result in Charpy V-notch testing to confirm notch toughness. The Panel finds that, by specifying Category III pipe as a minimum, Northern Gateway would obtain toughness data for its entire system that would be useful for pipeline integrity issues that might arise in the future.

The Panel notes that Northern Gateway has committed to using Category II pipe when needed. Since fracture propagation is not an issue on liquid pipelines, the Panel finds that requiring the use of the drop weight tear test would not provide data that would be needed for the project.

5.6 The Kitimat Terminal

Northern Gateway said that the Kitimat Terminal site on the west side of the Kitimat Arm would consist of a tank terminal and a marine terminal. Northern Gateway said that it would design, construct, and operate the Kitimat Terminal and associated facilities in accordance with applicable regulations and industry codes, and the standards that are referenced within them. The existing ground surface at the Kitimat Terminal rises steeply from the shoreline to an elevation of approximately 180 metres above sea level at the tank lot.

Northern Gateway said that purpose of the Kitimat Terminal facilities is to:

  • receive oil transported by the oil pipeline;
  • transfer oil to oil tanks;
  • load oil into tankers;
  • unload condensate from tankers;
  • transfer condensate to condensate tanks; and
  • transfer condensate to the condensate pipeline.

It said that the major tank terminal facilities would include:

  • 16 oil tanks and 3 condensate tanks;
  • hydrocarbon transfer systems, including custody transfer metering;
  • oil receiving facilities to reduce the pressure of incoming oil;
  • a condensate pump station; and
  • associated infrastructure, including a remote impoundment reservoir.

Northern Gateway said that its basis for determining the initial tank capacity was the assumption that the pipelines would transport four different oil commodities and a single condensate commodity. Northern Gateway said that general industry practice is to provide 50 per cent more capacity than the nominal capacity of the largest tanker that would load or unload at the terminal. To determine the required tankage capacity, Northern Gateway also modelled pipeline operations and potential interruptions to it, together with incoming and outgoing tanker movements.

Northern Gateway said that the applied-for tank numbers and sizes provide the required tank capacity requested by prospective shippers, as well as adequate product segregation and operational flexibility. In a potential expansion scenario with expanded throughput rates on either pipeline, additional tanks may not be required, as greater use of the existing tank facilities may result.

Northern Gateway said that all tanks would be equipped with floating roofs, complete with mechanical shoes and secondary seals to limit hydrocarbon vapour emissions.

Northern Gateway said that the marine terminal would include two tanker berths, one utility berth, and associated infrastructure. The marine terminal would be designed to accommodate various tanker classes, from VLCC (very large crude carriers) to Suezmax (average-sized tankers) to Aframax (smallest-sized tankers). It said that the marine terminal would have the capacity to load visiting tankers within 48 hours of berthing time. It said that the loading rate would be controlled to minimize the potential for static charges that could lead to fires.

Figure 5.6 Kitimat Terminal

Figure 5.6 Kitimat Terminal

Table 5.1 Tank Specifications

Item Metric Units Imperial Units
Tank Diameter 74.07 metres 243 feet
Tank Height 24.4 metres 80 feet
Roof Type Open-top external floating pontoon
Minimum Freeboard 1.05 metres 3.44 feet
Nominal Capacity 98,410 cubic metres 619,000 barrels
Working Capacity 87,440 cubic metres 550,000 barrels
Total working Capacity for 16 Oil Tanks 1,399,000 cubic metres 8,800,000 barrels
Design Injection Flow Rate per Oil Tank 150,100 cubic metres/day 944,000 barrels/day
Average Takeaway Flow Rate per Oil Tank 15,900 cubic metres/hour 100,000 barrels/hour
Total working Capacity for 3 Condensate Tanks 262,320 cubic metres 1,650,000 barrels
Design Injection Flow Rate per Condensate Tank 11,130 cubic metres/day 70,000 barrels/day
Average Takeaway Flow Rate per Condensate Tank 30,680 cubic metres/day 193,000 barrels/day

5.6.1 Structural design of the tanks

Northern Gateway said that it would design the Kitimat Terminal's tanks to meet American Petroleum Institute (API) 650, which has well-established design criteria for seismic design, as well as the National Building Code of Canada's structural provisions. It said that, due to the terminal's geographic location, the seismicity hazard is considered no higher than moderate, and is much lower than many other similar facilities along the coast. It said that it would construct the tanks on bedrock, providing favourable foundation conditions. Northern Gateway said that it would design the tanks so that potential forces or strains imposed by seismic events would not cause the tanks to rupture or collapse, although they may undergo plastic deformation (e.g., bulging). Because most tanks would not be full, actual seismic loads would be less than design maximums for most tanks at the terminal. Northern Gateway said that it would design piping systems attached to the storage tanks to have sufficient mechanical flexibility to accommodate tank wall and foundation displacements without damage that could cause a hydrocarbon release.

5.6.2 Secondary containment

Northern Gateway said that the tank terminal, and the tank for recovered oil at the marine terminal, would have containment berms. The berm wall design would likely be constructed of engineered fill or would be a vertical concrete wall system. It would design the tank terminal berm system to allow overflow between tanks before overflow of the perimeter walls. The containment berms would be designed to collect liquids and direct them through a pipe system to the remote impoundment reservoir. The remote impoundment reservoir is shown in Figure 5.6. All secondary containment facilities, including the bermed areas and the impoundment reservoir, would be double-lined with an impervious membrane liner and would be equipped with a leak detection system.

Northern Gateway said that the remote impoundment reservoir location at the southeast end of the tank lot would conform to the current British Columbia Fire Code. Its size would be:

  • 100 per cent of the volume of the largest tank in the tank terminal; plus
  • 10 per cent of the aggregate volume of the 18 remaining tanks; plus
  • an allowance for potential future tanks; plus
  • 100 per cent of the runoff from the catchment area during a 1 in 100-year, 24-hour storm event; plus
  • the amount of fire water generated from potential firefighting activities at the tank terminal.

Northern Gateway said that water from the secondary containment reservoir's catchment area may be released to the ocean, providing the oil-water concentration is less than 15 parts per million.

Views of the Panel

The Panel is satisfied with Northern Gateway's current Kitimat Terminal design, as it committed to designing, constructing, and operating the facilities in accordance with applicable regulations, industry codes, and standards. The Panel notes Northern Gateway's evidence that seismicity at the terminal site is considered to be moderate and that it would design the facilities to meet API 650 and the National Building Code of Canada.

Northern Gateway proposed a number of precautions to limit leaks and ruptures. The Panel is not satisfied that the method Northern Gateway used to calculate secondary containment volumes adequately considers the potential for multiple tank ruptures from a single event, such as an earthquake, or the environmental consequences should this occur. Full tanks would be the most vulnerable to severe earthquake damage and evidence indicated that it is unlikely that all tanks would be full at any given time. The Panel requires, as a precautionary measure, that Northern Gateway construct secondary containment to accommodate six times the volume of the largest tank in the tank terminal, plus an allowance for peak precipitation, potential future tanks, and firefighting activities. This volume is roughly equivalent to the number of full tanks required to fill a VLCC, plus the volume that might be in tanks from a recently-unloaded Suezmax condensate tanker.

5.7 Pump stations

During its hydraulic analyses, Northern Gateway determined the number and horsepower of pumps required at each station to achieve the design capacities of the oil and condensate pipelines.

The oil pipeline would require seven pump stations, including the initiating pump station at the Bruderheim Station. The condensate pipeline would require nine pump stations, including the initiating pump station at the Kitimat Terminal. Six of the eight proposed intermediate pump stations between Bruderheim and Kitimat would have pumps for both the oil and condensate pipelines. The remaining two intermediate stations would only have pumps for the condensate pipeline (see Table 5.2).

Automated pump station bypass assemblies would be installed at the intermediate oil pump stations to facilitate batch separation operations. Each pump station would be controlled using a variable-frequency drive (VFD) system that would supply a soft start for the pump motors and provide primary station pressure control. In its application, Northern Gateway initially said that stations would also have pressure control valves (PCVs) on the discharge side to provide secondary station pressure control.

Northern Gateway said that it would finalize each station's design and actual layout during detailed engineering, once final design parameters and site-specific data are available. This includes the requirement for flow recirculation lines that may maintain minimum flow at start-up and allow for throughput volumes below the design values. It would also determine the need for additional variable-frequency drives at the initiating and other stations during detailed engineering. Northern Gateway said that, if it considers the variable-frequency drive system implemented in final design to be suitably reliable, pressure control valves for secondary station control might be eliminated, subject to other operational considerations.

Engineered containment berms would be constructed around the perimeter of each station site to prevent surface runoff from flowing off-site and to contain any leaked hydrocarbons. The area inside the berm would be graded so that surface runoff would collect in a lined containment pond. The containment pond capacity would be approximately 1,600 cubic metres (10,000 barrels). The water in the containment pond would be tested and treated as necessary before being discharged off-site. The pump house buildings would be enclosed structures with concrete floors.

Table 5.2 Summary of Pump and Motor Sizes

Station Name Approximate Kilometre Post Purpose Oil Pumps and Motor size Condensate Pumps and Motor Size
Bruderheim 0 Oil 6 @4,290 kW
(5,750 HP)
N/A
Whitecourt 204.5 Oil and Condensate 6 @4,290 kW
(5,750 HP)
2 @4,290 kW
(5,750 HP)
Smoky River 418 Oil and Condensate 5 @4,290 kW
(5,750 HP)
2 @4,290 kW
(5,750 HP)
Tumbler Ridge 600.3 Oil and Condensate 3 @4,290 kW
(5,750 HP)
2 @4,290 kW
(5,750 HP)
Bear Lake 718.8 Oil and Condensate 3 @4,290 kW (5,750 HP) 2 @4,290 kW
(5,750 HP)
Fort St. James 827.8 Oil and Condensate 3 @4,290 kW
(5,750 HP)
2 @4,290 kW
(5,750 HP)
Burns Lake 928.8 Oil and Condensate 3 @4,290 kW
(5,750 HP)
2 @4,290 kW
(5,750 HP)
Houston 1006.2 Condensate N/A 2 @4,290 kW
(5,750 HP)
Clearwater 1130.0 Condensate N/A 2 @4,290 kW
(5,750 HP)
Kitimat 1177.6 Condensate N/A 2 @4,290 kW
(5,750 HP)

Notes: All pumps would be electrically driven and connected in series HP – horsepower kW – kilowatt

Views of the Panel

The Panel is satisfied with Northern Gateway's current pump station designs, including the containment pond capacities. The Panel is of the view that safety systems, such as overpressure protection, should have some redundancy, as a precaution. The Panel requires Northern Gateway to install both pressure control valves and variable-frequency drives at all pump stations.

5.8 Mainline valves and valve locations

Northern Gateway said that mainline valves (MLVs) on the oil and condensate pipelines would allow them to be shut down in a controlled manner, either for regular operational and maintenance requirements or for responding to a potential operating emergency. It said that, in the unlikely event that a pipeline fails or is damaged, the valves enable its operations staff to isolate an outage and minimize release volumes. Northern Gateway determined a preliminary list of valve locations after considering potential release volumes, environmental sensitivity, and potential environmental effects. It calculated the potential release volumes with a proprietary model based on a dynamic (i.e., pressurized) release prior to full valve closure, and a static (drained down) volume after valve closure. Figure 5.7 illustrates the potential for drain-down following valve closure. Valve locations were adjusted after taking into account terrain and service access requirements. Northern Gateway used a spill trajectory model to determine the potential spill extent, both on and off the right-of-way.

During the Panel's process, Northern Gateway updated the preliminary list of valve locations. In determining these locations, it assumed that all block valves would be fully automated and remotely operated from the Enbridge Control Centre in Edmonton. It also assumed that the valves would be fully closed within 13 minutes of detecting an alarm event. This includes 10 minutes of detection and response time and 3 minutes for full valve closure.

Northern Gateway used the following criteria in its engineering assessment to locate valves:

  • valves placed at each of the pump stations, the Kitimat Terminal, the Bruderheim Station, and the tunnel portals;
  • valves placed at all major water crossings with a channel width greater than, or equal to, 30 metres; and
  • valves placed using a guideline of limiting the potential release volume to less than 2,000 cubic metres at locations meeting the following criteria:
  • watercourses with a channel width greater than 10 metres and high fish sensitivity;
  • valves placed to limit the potential release volume to less than 2,000 cubic metres along zones where a spill may affect tributaries to rivers with high fish sensitivity, such as the Upper Kitimat valley;
  • enhanced protection of high-value salmon habitat in the Fraser, Skeena, and Kitimat watersheds;
  • watercourses with high-volume downstream intakes for potable water or high-value commercial use; and
  • natural topographic variations can be considered in determining potential release volumes and valve site locations.

Northern Gateway said that specific valve placement was determined by factors such as:

  • locations not subject to geohazards such as slides, avalanches, avulsion, or lateral erosion of streams, rock fall, or flooding;
  • ground access, preferably all-season;
  • proximity to local power supply;
  • level or gently-sloping ground with sufficient room to service the valves;
  • existing land use, with the intention to avoid locations where valve placement may be a hindrance to other land uses or users;
  • avoiding locations, or providing appropriate protection, where third party strikes are a risk; and
  • placing oil and condensate valves at a common site.

As a result of these updates, Northern Gateway proposed 39 additional valves for the oil pipeline and 52 for the condensate line, bringing the total number of valves for each pipeline to 132.

Northern Gateway said that it would review and update block valve locations as engineering activities progress. It said it would take into account revised assumptions for valve design and operations, pipeline route changes, fisheries, community and Aboriginal inputs, and additional engineering and environmental information.

One intervenor said that the potential release volumes are based on Northern Gateway's interpretation of CSA Z662-11 and that they have not been justified as the highest achievable volumes. It said that the valve placements included in Route Revision V, Northern Gateway's latest route revision, were not scrutinized and tested by cross-examination.

Another intervenor said that the Panel should impose a condition requiring Northern Gateway to revise its valve placement strategy so that release volumes on either pipeline during a full-bore rupture would be no more than 100 cubic metres for 13-minute shutdown scenario. It said that this should apply for the life of the pipelines, and to any future capacity expansions.

Views of the Panel

The Panel finds that a pipeline rupture in certain areas along the route could release high volumes of oil or condensate. Properly-placed isolation valves would limit the consequences of a rupture and the corresponding scale and complexity of the emergency response. The Panel finds that Northern Gateway has not demonstrated that the calculated potential release volumes along the route are as low as practicable. A significant percentage of the volume spilled is dependent on the drain-down after a pipeline is shut down and the pipe segment is isolated.

Pipeline valves also introduce a risk of leaks from equipment failure at the valve locations that is higher than the risk of leaks from a pipeline rupture. These leaks would be harder to detect than pipeline leaks and could continue for an unspecified period of time before discovery. The Panel is satisfied that more valves would reduce potential release volumes from a rupture (a high consequence, low probability event) at the expense of an increased potential for leaks (a lower consequence, but higher probability event).

The Panel has not specified a maximum release volume of 100 cubic metres using the 13-minute shutdown scenario, as it is not practicable. For the oil pipeline, a rupture under dynamic (i.e., pressurized) conditions would require less than 2 minutes to discharge 100 cubic metres at the pipeline's average capacity of 83,400 cubic metres per day, not including drain-down volumes.

The Panel requires Northern Gateway to re-evaluate release volumes and the valve placement required to decrease them to as low as practical. The Panel requires Northern Gateway to provide rationales for the potential release volumes, develop spill extent mapping, and identify geohazard locations to facilitate assessment and to verify that the pipelines in areas potentially affected by geohazards have low potential release volumes.

Figure 5.7 Drain Down Volume After Isolation

Figure 5.7 Drain Down Volume After Isolation

5.9 Joining and non-destructive examination

The National Energy Board Onshore Pipeline Regulations include the following requirements for welding:

16. A company shall develop a joining program in respect of the joining of pipe and the components to be used in the pipeline and shall submit it to the Board when required to do so.

17. When a company conducts joining on a pipeline, the company shall examine the entire circumference of each joint by radiographic or ultrasonic methods.

Northern Gateway committed to developing and submitting to the National Energy Board a comprehensive project-specific Joining Program. It said that its submission would be as timely as practical following preliminary qualification of the welding procedures for pipe representative of what would be manufactured for the project. It would update its program as necessary after final testing with project production pipe, before starting pipeline welding.

Northern Gateway said that line pipe field girth welding would be by mechanized gas metal arc welding (GMAW) or manual shielded metal arc welding (SMAW). Tie-in welding would likely involve a combination of manual shielded metal arc welding and semi-automatic arc welding.

Northern Gateway said that large-diameter pipeline construction routinely requires a number of different welding procedures. Typically, one welding process would be identified as the "production welding process" for a given construction spread. A variety of welding processes and related welding procedures are used to join pipe or repair welds, and their use depends on the circumstances. Northern Gateway said that it would consider variables when establishing its welding procedures. These variables include the pipeline design and operational stresses, material specifications, temperature, and wall thickness changes.

During the Panel's process, Northern Gateway had not yet determined which welding processes would be used in every situation, but said that it was optimistic that it would be in a position to specify mechanized gas metal arc welding for the condensate pipeline. It would make this decision following extensive due diligence to determine the suitability of this process for pipes with outside diameters less than, or equal to, 610 millimetres (24 inches).

For exceptionally high stress/strain design situations, Northern Gateway said it would use a pipe segment-specific decision record process where subject matter experts, including specialist consultants, would specify the most appropriate welding and non-destructive testing processes and procedures. This could include gas metal arc welding (which is inherently low hydrogen), low-hydrogen-dominated shielded metal arc welding, or semi-automatic procedures.

One intervenor questioned the scope of the Welding Procedure Specifications and the extent of inspections and audits, and commented on the National Energy Board's role in this regard.

Views of the Panel

The Panel finds that Northern Gateway's development of the project-specific Joining Program meets the engineering technical requirements for constructing this project. The Panel requires Northern Gateway to file the Joining Program with the National Energy Board to facilitate compliance verification before starting construction.

5.9.1 Non-destructive examination of final tie-in welds

The National Energy Board Onshore Pipeline Regulations require companies to examine the entire circumference of each pipeline joint by radiographic or ultrasonic methods.

Northern Gateway said that its comprehensive project-specific Joining Program would be submitted on its behalf by Enbridge following preliminary qualification of the Welding Procedure Specifications. These specifications would require manual cellulose shielded metal arc welding for final tie-in welds. The electrodes used for shielded metal arc welding would have relatively-high hydrogen content, requiring a controlled cooling rate to enable diffusion of the hydrogen away from the weld.

By definition, final tie-in welds are not subject to final hydrostatic or pneumatic strength testing. Northern Gateway said that cracks in girth welds are currently the most significant construction integrity concern for higher grades of micro-alloyed steels. It would use delayed non-destructive examination to check for the presence of delayed hydrogen-assisted cracking for all final tie-in welds. Northern Gateway said that, by diligently using a matrix of Welding Procedure Specifications and visual and non-destructive examination best practices, latent hydrogen-assisted cracking in cellulosic shielded metal arc welding can be eliminated.

Northern Gateway said that hydrogen-assisted cracking is one of two primary mechanisms of construction girth weld cracking, the other mechanism being caused by excessive stress being applied prior to adequate weld reinforcement. It said that strict adherence to the Welding Procedure Specifications is critical in preventing the occurrence of hydrogen-assisted cracking. This means assuring a field focus of avoiding residual hydrogen in welds, mitigating the residual stresses from weld joint fit-up related to ovality or high-low alignment and designed differential wall thicknesses, applying the required preheat, maintaining the required inter-pass temperatures, and controlling the cooling rate. Northern Gateway said that it would take all these steps to avoid the potential for hydrogen entrapment and limit the formation of a weld microstructure susceptible to hydrogen or construction stress cracking.

Northern Gateway said that delayed hydrogen-assisted cracking caused by hydrogen entrapment can be very small, or tight initially, and can grow to more detectable levels after completing welding, often inclusive of an extended cooling period.

Northern Gateway said that Enbridge frequently conducts delayed non-destructive examination, during the day following weld completion, as a supplemental means to mitigate risks of latent hydrogen-assisted cracking in cellulosic shielded metal arc welding used for final tie ins. Northern Gateway said that the non-destructive examination would be delayed a minimum of 18 hours after weld completion.

In response to the Panel's potential condition requiring a 48-hour delay before the non-destructive examination of tie-in welds, Northern Gateway said that it preferred Enbridge's current 18-hour delay practice since it is a proven method. It said that there was no incremental risk mitigation by increasing the delay beyond 18 hours.

C.J. Peter Associates Engineering supported the requirement for a 48-hour delay before the non-destructive examination of tie-in welds, emphasizing that this delay should be required for both tie-in welds and repair welds.

Views of the Panel

The Panel finds that delayed non-destructive examination of all final tie-in welds is essential for both the oil and condensate pipelines. Northern Gateway said that Enbridge's current practice of delaying non-destructive examinations at least 18 hours after weld completion is adequate. The Panel is concerned that the formation of hydrogen-assisted cracking might continue beyond 18 hours. One method of detecting these cracks, other than by radiography or ultrasonic inspection, is a sensitive pipeline leak test. Final tie-in welds are not subject to these tests because they connect sections of pipeline that have already been pressure tested in situ.

The Panel agrees with Northern Gateway that cracks in girth welds are a significant construction integrity concern for higher grades of micro-alloyed steels. The Panel finds that the safety, environmental, and economic consequences of a rupture, regardless of the likelihood, may be very high for this project. The Panel requires Northern Gateway to conduct non-destructive examination of final tie-in welds a minimum of 48 hours after weld completion for safety and to reduce risk.

5.9.2 Radiographer and ultrasonic technicians

Northern Gateway said that it would use only Canadian General Standards Board-certified radiographers and ultrasonic technicians for final non-destructive examination interpretation, in accordance with CSA Z662-11. Should there be a shortage of qualified non-destructive examination personnel, Northern Gateway said that it would use American Society for Non-Destructive Testing-certified personnel to assist with the non-destructive examination inspection process. Northern Gateway proposed that Canadian General Standards Board-certified operators and technicians would conduct and/or approve all final interpretations and acceptance of welds.

In response to the Panel's potential condition to require using only Canadian General Standards Board-certified radiographers and ultrasonic technicians to operate non-destructive examination inspection equipment and for final interpretation of radiographic film and ultrasonic inspection system results, Northern Gateway said that there is no practicable way to meet this requirement. It said that there are an insufficient number of these certified pipeline inspection operators in Canada and that Enbridge currently uses radiographers and ultrasonic technicians with equivalent certifications. Northern Gateway requested that this condition be removed.

Natural Resources Canada proposed revised condition wording that would require Canadian General Standards Board-certified personnel to be specified for operating all types of non-destructive examination equipment, not just for radiographic and ultrasonic equipment.

Views of the Panel

Non-destructive examination is a key component in managing modern pipeline system integrity. CSA Z662-11 requires radiographers to be qualified as specified in CAN/CGSB-48.9712. This standard also requires ultrasonic inspectors and radiographers doing radiographic image interpretation to be qualified as specified in CAN/CGSB-48.9712 to Level II or III. The Panel requires Northern Gateway to meet this standard.

5.9.3 Pressure testing

Northern Gateway said that each pipeline section would be pressure tested in accordance with CSA Z662-11 and that, in most cases, water would be used. It said that it would examine the feasibility of using compressed air for pressure testing at certain locations, particularly in isolated steep mountainous terrain or in areas with limited water supply. It would select pipeline sections to be considered for air testing during detailed engineering. Northern Gateway confirmed that it would use Category II steel for the pipe sections to be air tested, to provide greater notch toughness. It said that air testing may be a good test for detecting leaks from small defects if the test is of sufficient duration.

For the Kitimat Terminal, Northern Gateway said that it would test the various systems, including tanks, piping, control systems, and other infrastructure, in accordance with current regulations and industry standards. Tanks would be hydrostatically tested with fresh water or storm water collected in the remote impoundment reservoir. Water would be transferred from tank to tank for each subsequent test. After completing all tests, the water would be managed according to applicable regulations. Piping would by hydrostatically tested with water collected in the remote impoundment reservoir or trucked in from off site. Northern Gateway would develop detailed hydrostatic testing plans before testing.

Northern Gateway said that it would seek leave to open from the National Energy Board after successfully completing pre-commissioning of the terminal facilities and tanks, before introducing hydrocarbons and start-up.

Views of the Panel

Pressure testing in accordance with CSA Z662-11 involves a strength test and a leak test, which can be performed with liquid or air. The Panel is of the view that air testing can effectively demonstrate that the strength of the pipe or pressure vessel is able to withstand the pressure it is tested to. The Panel is not convinced that air testing can effectively determine the presence of pinholes or fine through-wall cracks for larger diameter pipelines, due to the compressibility of air. While testing with a liquid medium may be troublesome, given the concerns regarding potential leaks expressed during the hearing, the Panel requires Northern Gateway to pressure test the pipelines with water and to report any failed tests and their causes on a monthly basis.

5.10 Leak detection

5.10.1 Leak detection system operations

Northern Gateway said that the Enbridge Edmonton Control Centre would monitor and operate the proposed pipelines and related facilities. The Kitimat Control Centre would monitor and operate the Kitimat Terminal facilities associated with vessel loading and unloading. A supervisory control and data acquisition (SCADA) system would enable the pipelines and facilities to be monitored and remotely operated simultaneously from both control centres. Emergency shutdown systems would be capable of being initiated remotely or locally.

Northern Gateway said that the SCADA system would include a redundancy of SCADA systems and associated hardware within the control centres, and also a backup control centre. The telecommunication system would include a redundancy of communications to all terminals, pump stations, and other remote sites deemed critical for safe operation. Northern Gateway said that it was also investigating a number of telecommunications technologies, such as dedicated fibre optics for use on the pipeline right-of-way.

Northern Gateway indicated that, by placing ultrasonic flow meters at every pumping station, combined with the custody transfer meters, and pressure transmitters around every valve site, it would probably have one of the best-instrumented pipeline systems in the world.

5.10.2 Leak detection methods

Northern Gateway said that Enbridge uses the following four primary monitoring methods to detect possible leaks on its pipelines and that these would also be used on the proposed pipelines:

  • Visual surveillance and reports, including aerial and ground patrol reports and third party reports of oil or oil odours. Aerial patrols occur a minimum of 26 times per year at no greater than 3-week intervals.
  • Scheduled line balance calculations at fixed intervals (over/short reports) using a commodity movement tracking system. This compares volumes entering the pipeline system to deliveries leaving the pipeline, and then calculates any overall imbalance.
  • Continuous controller monitoring of pipeline conditions at the Enbridge Edmonton Control Centre using the SCADA system that reports key flows, pressures, and other sensor data every few seconds.
  • The Material Balance System, which is a sophisticated real-time Computational Pipeline Monitoring system supported from the Edmonton Control Centre 24 hours per day.

Northern Gateway said that its system would be designed to meet the requirements of CSA Z662-11 Annex E, U.S. DOT's CFR 49 Part 195, and API 1130. Northern Gateway said that the Computational Pipeline Monitoring system has a threshold accuracy of 1.5 to 3.0 per cent, depending on the pipeline segment length for which the volume balance is being calculated, and that the meters had a 1 to 2 per cent range of sensitivity. It said that it uses API 1149 methods, which are industry-accepted for determining leak detection system sensitivity. AP1 1149-predicted thresholds and sensitivity were tested with API 1130 methods, and the results of fluid withdrawal tests and these lined up well with the API 1149 predictions.

Northern Gateway said that its Material Balance System can effectively model column separation, which has the potential to mask and delay leak detection when the leak is in the vicinity of column separation and begins at approximately the same time that the column separation forms. Northern Gateway identified potential areas at higher risk of column separation. It said that, with pressure transmitters located at these critical areas, it may implement operating procedures to maintain sufficient operating pressures to prevent column separation from occurring.

As part of its ongoing consultation and project review, Northern Gateway committed to a number of potential design features that would enhance pipeline safety and reliability over and above standard industry practice. One such commitment was to implement a second real-time leak detection system that would complement the existing Enbridge real-time transient modelling leak detection system.

Some technologies that Northern Gateway said it is actively investigating include:

  • "Computational Pipeline Monitoring" leak detection systems that use algorithmic tools to enhance the pipeline controller's ability to detect leaks;
  • highly-permeable vapour sensing tubes, installed along the pipeline, that include pumps to push the air column in the tube past a gas detection unit at a constant speed (not a real-time detection system);
  • chemical-sensing cables that physically or chemically change when in contact with a contaminant that causes a detectable voltage drop;
  • fibre-optic cable systems that detect leaks based on temperature changes in the surrounding soil;
  • acoustic or negative pressure wave detection systems that are based on the negative pressure waves associated with the onset of a leak or break;
  • aerial-based remote-sensing leak detection systems that use thermal cameras, laser-based technologies, or gas-sampling technologies installed on aircraft (not a real-time detection system); and
  • in-line inspection tools that detect acoustic emissions associated with leaks (not a real-time detection system).

Northern Gateway said that its procedures would require initiating a line shutdown within 10 minutes of receiving an unexplained Material Balance System alarm (this is the "10-minute rule"). Three additional minutes would be required for segment isolation to occur once the shutdown was initiated. In response to questions by Haisla Nation, Northern Gateway said that it would look at the feasibility of an automatic pipeline shutdown after the 10-minute analysis period, assuming it may do so safely and reliably. Before it could commit to this, Northern Gateway said it would need to go through its change management processes and do associated hazard and risk assessments. For operational reasons, it said it preferred to implement a controlled system shutdown, as opposed to an automatic emergency shutdown.

Northern Gateway said that, regardless of the means of detection, it is the leak detection time that is of concern and it would strive to minimize this time, especially for rupture conditions. Northern Gateway provided details on detection times for 11 leaks greater than 159 cubic metres (1,000 barrels) on the Enbridge system in the United States. In most cases, the leak (or rupture) was detected in less than 5 minutes. The Line 6B rupture in Marshall, Michigan, was not recognized by operators for 17 hours, although instrumentation detected the leak within 5 minutes.

Northern Gateway was questioned about detecting larger leaks on Enbridge's system, including the Marshall, Michigan, rupture and a pinhole leak on the Norman Wells Pipeline.

Regarding the Marshall, Michigan, rupture, Northern Gateway said that the SCADA and leak detection systems detected the leak within 5 minutes, but that human error and systemic problems lead to Enbridge's delayed response. Specifically, two "golden rules" were not followed: adherence to the emergency procedures and, when there is any doubt, shut the system down and bring it to a safe state. Northern Gateway said that Line 6B was in a transient state at the time and the operators incorrectly interpreted the cause of the alarm condition as column separation of the product within the pipeline.

Northern Gateway said that Enbridge underwent a total reorganization after the leak occurred. It said that Enbridge enhanced its management systems to clearly define roles and responsibilities, revisited the interface between the SCADA system and operations staff, incorporated fatigue and alarm management, and made changes to its training programs. Northern Gateway said that Enbridge also launched a safety culture initiative. Northern Gateway said that its pipelines and Material Balance System would be designed to ensure the conditions leading to column separation, and the false detection of column separation, would not occur.

Northern Gateway said that the Norman Wells Pipeline leak was a pinhole leak that released a volume of 258 cubic metres (1,628 barrels). It said that pinhole leaks are difficult to detect with instrumentation, but that a pressure test or in-line inspection tool may be able to identify them. In this case, the oil was trapped under frozen ground in winter and was not discovered until the ground thawed in spring.

Douglas Channel Watch questioned whether the Enbridge Edmonton Control Centre would monitor and control Northern Gateway's pipelines, noting that this control centre also monitored and controlled Enbridge's Line 6B when it experienced the rupture in Marshall, Michigan.

Ms. Wier questioned leak detection system threshold limits, sensitivities, and success. She said that significant releases may occur before being detected by leak detection systems or other means.

Views of the Panel

Reliable SCADA and leak detection systems are necessary for safe and efficient pipeline system operations. The Panel finds that Northern Gateway's system would be well-instrumented and would meet the requirements of CSA Z662-11 Annex E, U.S. DOT's CFR 49 Part 195, and API 1130. To facilitate monitoring of design and implementation issues, the Panel requires Northern Gateway to describe its SCADA and leak detection systems, relevant hardware, performance measures, and quality assurance program before starting construction. The Panel also requires Northern Gateway to report on the results of its quality assurance program for the project's operational life.

The Panel finds that Northern Gateway's proposed combination of visual surveillance, aerial and ground patrols, and SCADA and leak detection systems is consistent with industry practice, and recognizes that the applicability and effectiveness of its various proposed leak detection methods depend on the nature of the leak or rupture.

The ability to detect leaks and ruptures quickly is an important factor in spill response and in minimizing the volume of hydrocarbons released. The Panel acknowledges the Haisla Nation's suggestion that the default should be to shut down a pipeline 10 minutes after detecting a leak, unless overridden by an operator. The Panel also acknowledges Northern Gateway's intention to follow established shutdown procedures, as opposed to invoking an emergency shutdown. The decision to delay shutdown procedures must be weighed against safety and environmental concerns, especially in the event of a rupture. The Panel finds that Enbridge (hence, Northern Gateway) has enhanced its management systems to clearly define roles and responsibilities, revisited the interface between the SCADA system and operations staff, incorporated fatigue and alarm management, and made changes to its training programs.

The Panel is also satisfied that Enbridge has launched a safety culture initiative. The National Energy Board would assess control room performance as part of its audit program. The Panel has determined that, with these improvements, the safest and more responsible approach to operating the pipelines is not to have an automatic shutdown that would need to be overridden by human action. The Panel is convinced that human intelligence, supported by good SCADA and leak detection systems at its current state of technology, would optimize safety and environmental protection.

Regarding Northern Gateway's assurance that it would design its pipelines so that column separation, and the false detection of it, would not occur, the Panel finds that the pipelines may be required to operate at much less than the design operating pressure under certain circumstances. In such instances, there would be an increased likelihood of column separation occurring. The Panel requires Northern Gateway to identify areas where column separation may occur and to install pressure transducers in these areas, as well as alarms and procedures to prevent its occurrence.

The Panel accepts Northern Gateway's commitment to implement complementary leak detection systems. The Panel recognizes that leak detection is an evolving technology and understands Northern Gateway's plans to investigate options and implement the technology with the greatest chance of success. The Panel requires Northern Gateway to report on its assessment, implementation plans, and quality program for complementary leak detection technologies. The Panel also requires Northern Gateway to report on the observed detectability, sensitivity, reliability, robustness, and accuracy of the leak detection systems, for the project's operational life.

5.11 Corrosiveness of dilbit

Many participants in the Panel's process were concerned about the corrosiveness of dilbit. Two reports filed by ForestEthics Advocacy served as primary sources for these concerns. The first report, Tar Sands Pipeline Safety Risks, was authored by the Natural Resources Defense Council, National Wildlife Federation, Pipeline Safety Trust, and the Sierra Club. The second report, Pipeline and Tanker Trouble, was authored by the Natural Resources Defense Council, the Pembina Institute, and Living Oceans Society. The Haisla Nation filed a third report, authored by G. Bakker, The Corrosive Nature of Diluted Bitumen and Crude Oil Literature review.

In response to these reports, Northern Gateway filed an independent study, Comparison of the Corrosivity of Dilbit and Conventional Crude. Northern Gateway's report examined the properties of 15 representative crudes and dilbits in western Canada.

The primary concerns cited in the first two referenced reports regarding dilbit corrosiveness included:

  • dilbit contains 5 to 10 times more sulphur, which can lead to pipeline embrittlement;
  • dilbit contains 15 to 20 times higher organic acid content than conventional crude;
  • dilbit has a high concentration of chloride salts, which can lead to chloride stress corrosion in high temperature pipelines;
  • oil sands crude contains more abrasive sand particles making dilbit a sort of "liquid sandpaper";
  • dilbit has a higher viscosity than conventional crude and creates higher temperatures as a result of friction;
  • the provincially-regulated Alberta pipeline system has had 16 times as many spills due to internal corrosion than the United States pipeline system, which indicates that dilbit is more corrosive than conventional crudes;
  • a combination of chemical corrosion and abrasion dramatically increases deterioration;
  • higher operating temperatures increase the corrosion rate (a rule of thumb is that for every 10 degree Celsius increase in temperature the corrosion rate doubles);
  • dilbit pipelines may be subject to a higher inci-dence of external stress corrosion cracking; and
  • regulations do not distinguish between conventional crude and dilbit when setting minimum standards for oil pipelines.

The potential for under-deposit corrosion beneath sludge deposits was discussed during the Panel's process. The Northern Gateway report said that, while it would be expected to find sludge deposits at the lowest spots in a pipeline, Enbridge observed, and it has been reported in scientific literature, that under-deposit corrosion in its dilbit lines also occurred near overbends. Overbends are locations of low fluid shear stress. Northern Gateway's report said that little is known about the sludge deposition mechanism and the role of dilbit chemistry. The report recommended that research should continue to improve understanding of sludge formation, the resulting corrosion mechanism, the role of dilbit chemistry and solids, mitigation practices and frequencies, and preventive measures. The report said that Enbridge has been quite successful in mitigating under-deposit corrosion, but there were uncertainties regarding each technique's effectiveness and the required application frequency.

C.J. Peter Associates Engineering referred to a paper co-authored by an Enbridge employee, which indicated that, for heavy oil pipelines, corrosion also occurs on the pipe bottom of overbends. The paper said that this deposition is attributed to "inertial forces that increase the thickness of the boundary layer at the pipe floor thereby reducing the flow forces responsible for mobilizing solids." C.J. Peter referred to a passage in the same paper indicating that a crude oil pipeline with low corrosion rates by conventional corrosion monitoring standards was found to have locally-severe under-deposit pitting.

Northern Gateway said that it would monitor incoming crude batches to ensure that they meet the applicable oil pipeline tariff requirements. All oil would be tested for adherence to the Enbridge Crude Petroleum Tariff, which specifies acceptable crude quality, such as maximum temperature, maximum density, maximum allowable basic sediment and water (BS&W), and viscosity. Every commodity nominated for transport on the oil pipeline would require prior approval through the Enbridge New Service Request Process, currently implemented on the Enbridge Mainline System.

Northern Gateway anticipated the precipitation of solids from dilbit. It said that Enbridge conducts regular analyses of its pipeline operations to determine the potential for potentially-corrosive sediments to settle, contact, and persist on the pipe floor where they might cause corrosion. These analyses are used to determine the requirement for cleaning programs that would displace accumulated sediments. Northern Gateway said that any solids formation would be handled as per Enbridge's current operating standards and maintenance.

Northern Gateway said that the level of corrosive substances in dilbit (water, sediment, chemical species corrosive under normal pipeline operating conditions, and bacteria) is fundamentally similar to conventional heavy crude oils. It said that Enbridge conducts regular in-line inspections to identify corrosion metal loss processes.

Corrosion potential in the proposed pipeline was discussed during the Panel's process. Northern Gateway's semi-quantitative risk assessment (SQRA) identified an analogous pipeline (Line 4) in the Enbridge system. Line 4 has been operating since 1999 and has many of the same technical attributes of the proposed pipeline, including size, coating, flow mode (i.e., turbulent), internal corrosion control measures, and products delivered (including dilbit). The assessment indicated that internal inspections found no internal corrosion issues on Line 4.

Views of the Panel

The Panel is not convinced that dilbit, which meets the Enbridge Crude Petroleum Tariff, would be more corrosive than conventional heavy crude oils. The Panel has based this conclusion on the hearing evidence including the outcomes of Enbridge's management of internal corrosion issues on Line 4, which has no internal corrosion issues.

5.12 Risk approach

The Panel is not convinced that dilbit meeting the Enbridge Crude Petroleum Tariff would be more corrosive than conventional heavy crude oils. The Panel has based this conclusion on the hearing evidence including the outcomes of Enbridge's management of internal corrosion issues on Line 4, which has no internal corrosion issues.

In its application, Northern Gateway provided a table of the spill return periods for physiographic regions along the pipeline route. The likelihood of medium or large hydrocarbon releases occurring in selected regions and at specific locations along the route were calculated using National Energy Board failure data. It was expressed as a spill return period (years per spill). Northern Gateway said that, although numerous databases provide data for the pipeline industry worldwide, National Energy Board data is based on liquid hydrocarbon transmission lines under its jurisdiction, best representing the project. Results of the most recent analysis of the National Energy Board liquid pipeline failure database from 1991 to 2009 were used to represent applicable failure types. Northern Gateway said that the National Energy Board data, although based on recent performance, included pipelines up to 50 years old, built using older technology and material standards.

Northern Gateway said that the frequency results did not predict whether hydrocarbons would reach particularly sensitive locations. It said that the estimated probability of hydrocarbons reaching a watercourse is less than the probability of a release at any particular location along the pipeline route. This was based on elements such as topography, soil type, season, temperature, viscosity, distance, pipeline depth, engineering design, containment strategies, construction methods, and local conditions. The volume that might be released depends on many factors, including failure detection, shutdown time, hydraulic gradients, and valve spacing.

Northern Gateway said that it is committed to pipeline integrity management and maintenance and acknowledged its responsibility to conduct business to high standards of integrity, transparency, safety, and environmental protection. It said that preventative measures, monitoring, and mitigation are central to its pipeline integrity policies. For comparative purposes, Northern Gateway provided spill statistics for Enbridge's liquids pipeline system between 2005 and 30 September 2012. It said that it selected this timeframe because Enbridge typically provides 5 years of data for reporting purposes. It noted that release sizes differed slightly from other data because Enbridge categorizes spills greater than 15.9 cubic metres (100 barrels) as large. Evidence provided by Northern Gateway suggested that 92 per cent of the reported releases occurred within fenced facility yards and did not escape company property. It said that these involved relatively small volumes that Enbridge was able to immediately contain and clean up. It said that it was unlikely that small spills at facility sites would migrate beyond property boundaries during the project's lifespan.

5.12.1 Semi-quantitative risk assessment

Northern Gateway said that it recognized and shared the public's concern about the consequences of spills and that it was very much aligned with regulators and the public in wanting to avoid spills of any size. It said that the objective of its pipeline design, engineering, construction, and operations is to mitigate and manage the risk level, over the life of the pipeline, with the goal of avoiding spills of any size.

Northern Gateway said that, as part of its risk mitigation and management objective, it undertook a risk-based design process for the pipelines. It said that risk-based design is an iterative approach that evaluates and prioritizes risks associated with a preliminary design and the associated risk-drivers. It then establishes mitigation measures to be incorporated into the design to address the principal unmitigated risks. Northern Gateway's semi-quantitative risk assessment provided a risk assessment of a full-bore rupture releasing dilbit from the oil pipeline.

From the perspective of consequence mitigation, Northern Gateway said that the focus of its semi-quantitative risk assessment was on ruptures because ruptures have the most extreme consequence and are of the greatest interest in completing a risk-based design. Northern Gateway said that this was consistent with the Panel's guidance to characterize full-bore rupture effects. Northern Gateway said that any consequence-mitigation measures developed and incorporated into the design for mitigating ruptures would also be effective in mitigating less significant releases. Since Northern Gateway's failure likelihood assessment evaluates and characterizes all failure modes, including leaks and ruptures, it said that guidance from the quantitative failure likelihood assessment report would be used in the risk-based design process.

Northern Gateway said that the first step in the semi-quantitative risk assessment was to identify hazard and threat events, including:

  • internal corrosion;
  • external corrosion;
  • material and manufacturing defects;
  • construction defects (welding, fabrication, and installation);
  • incorrect operations;
  • equipment failure (such as pump stations components);
  • third party damage; and
  • geotechnical and hydrological threats.

Northern Gateway said that the next step was to determine the failure frequency based on reliability methods and expert judgement. It developed a quantitative failure frequency model for threats associated with constructing and operating its pipeline system. It said that historical pipeline industry failure statistics are not representative of modern pipeline designs, materials, and operating practices. It said that a review of industry failure statistics indicated that approximately 90 per cent of pipeline failures occur on pipelines installed in the 1970s or earlier. Northern Gateway identified 16 technologies and practices that have been largely developed since the construction of these pipelines, which it would use for the project.

Northern Gateway said that older pipeline designs were not optimized using modern modelling techniques, such as overland spill modelling and valve optimization, to minimize spills. It said that the consequences of older pipeline failures, as reported in industry incident databases, are usually more severe than would be the case for a pipeline designed using a modern risk-based design approach. It also said that another disadvantage of using industry failure databases as the basis for a quantitative risk assessment is that they do not address unique site-specific threats, such as geotechnical hazards.

To predict potential failure mechanisms and quantitative risk values for new pipelines, Northern Gateway's threat-based approach used actual operating data from recently-constructed (modern) pipelines with technology and products similar to that proposed, in conjunction with reliability-based methods relevant to the threat being considered. It used a quantitative failure frequency model using reliability methods to address the primary challenge associated with deriving quantitative risk values for new pipelines.

Northern Gateway said that the geotechnical work supporting its application was used to eliminate many significant hazards through routing choices. As a result, the geohazard evaluation only considered residual hazards associated with the applied-for route. The evaluation considered threats within the Project Effects Assessment Area, as well as hazards outside the corridor that may potentially affect the pipelines. Rock fall, debris flows, avalanches, and various forms of slides were assessed to distances of sometimes several kilometres from the pipeline route and were typically, although not always, assessed to the height of land above the corridor. Northern Gateway said that approximately 250 kilometres of the route (20 per cent) has associated geotechnical threats.

Northern Gateway said that the third step in the semi-quantitative risk assessment was to evaluate consequences, beginning with spill trajectory modelling to determine whether a product release would affect a consequence area. It said that effect magnitude is a function of spill volume, accessibility, and inherent sensitivity of the particular consequence area.

Northern Gateway said that the final step was to evaluate unmitigated risk severity. It used the risk matrix developed for the project to evaluate risk severity, which involved a combination of rupture frequency and rupture consequence.

Northern Gateway said that it considered the following consequence areas:

  • officially-designated protected areas, including federal and provincial parks, conservancies, and ecological and wildlife reserves;
  • settlements, including hamlets, villages, towns, and cities;
  • Indian reserves;
  • licensed water withdrawal locations related to human consumption or other uses, such as for industry and agriculture;
  • watercourses with endangered or harvested fish species;
  • wildlife habitat containing species likely to interact strongly with oil and likely to contain species at risk; and
  • wetlands, fens, and marshes.

Northern Gateway ranked these consequence areas based on sensitivity to an oil spill event. For example, fish-bearing watercourses containing species at risk or that have a conservation concern were ranked higher than other watercourses.

Spill volumes were calculated for each kilometre of the route and varied based on a number of factors, such as topography and valve placement. Spill volumes were ranked and Northern Gateway used this ranking to modify the consequence score.

Northern Gateway said that ease of access, either by highway or paved road close to the right-of-way, decreases the response time to access a spill location. The accessibility to each kilometre-long pipe-line segment was ranked according to whether the segment had nearby road access and whether the road was for all-weather or seasonal use. This rank-ing was also used to modify the consequence score.

The semi-quantitative risk assessment concluded that most of the pipeline route has a low-risk rating. It also confirmed a number of higher-risk areas, primarily associated with high-value watercourses such as the Kitimat River.

Northern Gateway said that the terrain and geotechnical conditions that it would encounter are similar to those of other liquid transmission pipelines in Canada and throughout the world. It said that the types of products to be carried by this pipeline are similar to those carried by existing pipelines in Canada and the United States.

Northern Gateway said that a release of any magnitude from the pipeline would be unacceptable and that it would undertake additional work during the detailed design phase to identify and apply mitigation to minimize the risk of a release.

Individual hazards and threats are discussed in the proceeding sections.

Views of the Panel

Risk assessments based solely on historical incident records provide poor insight into future performance since incident records do not account for new technology and learnings that occur from the incident investigations. Northern Gateway said that it strives for continued improvement. The Panel finds that Northern Gateway's semi-quantitative risk assessment is a sound approach to designing a pipeline system because it provides a framework to anticipate, prevent, manage, and mitigate potential hazards at the design stage of the project.

5.12.2 Internal corrosion control

Northern Gateway's reliability approach for internal corrosion used a superimposition of an analog in-line inspection dataset on its preliminary design and materials, that took into account tool measurement error and corrosion growth. To ensure that the internal corrosion mechanism and corrosiveness of the analog in-line inspection dataset was representative, Northern Gateway examined several factors: water content, erosion and corrosion, flow velocity, flow mode, temperature, susceptibility to under-deposit corrosion (e.g., solid deposition, microbiologically-induced corrosion, potential, and water chemistry), and mitigation measures (e.g., using inhibition, biocides, or pigging). Northern Gateway determined that in-line inspection data from Enbridge's nominal pipe size (NPS) 36 Line 4 would be most representative of the corrosion conditions expected on the proposed oil pipeline. Line 4 was inspected several times and the results were reviewed. Northern Gateway said that no evidence of active internal corrosion was found. It said that the proposed oil pipeline would operate in fully-turbulent mode, resulting in full entrainment of what little water is present. Its maximum basic sediment and water tariff specification for the proposed oil pipeline would be 0.5 per cent, as is the case for Line 4. Considering these operating conditions, Northern Gateway said that no significant internal corrosion is expected on the oil pipeline and the failure probability for this threat is negligible.

Northern Gateway said that it would manage any internal corrosion on either the oil or condensate pipeline through periodic cleaning programs and condition monitoring by scheduled in-line inspections. It added that it would conduct chemical treatment on its pipeline systems when deemed appropriate to do so.

Views of the Panel

The Panel accepts Line 4 as an appropriate analog because it transports similar products and has similar physical characteristics as the proposed oil pipeline, such as size, operating temperature, flow mode, and flow velocity. Based on the results of Line 4 monitoring, the Panel is of the view that Northern Gateway's periodic cleaning and condition monitoring program would adequately mitigate internal corrosion issues on the proposed pipelines.

5.12.3 External corrosion control

Northern Gateway identified external corrosion as one of eight threats to the proposed pipeline system for input into the semi-quantitative risk assessment. The semi-quantitative risk assessment identified influences on the susceptibility to external corrosion, referred to as "threat attributes," as being:

  • coating type;
  • cathodic protection;
  • soil characteristics (e.g., acid-generating rock);
  • above-ground pipe (including the Hoult and Clore tunnels, and possible aerial crossings of gorges and watercourses);
  • casings (possibly used to stabilize trenchless crossings); and
  • in-line inspection data from the analog pipeline (Line 4).

Northern Gateway said that it would identify locations of acid-generating rock and develop mitigation plans in the detailed engineering phase. It would consider factors influencing the susceptibility to atmospheric corrosion during detailed design. It would also consider measures, such as filling the annulus between the pipe and any casing, during detailed design.

To model the failure frequency due to external corrosion, Northern Gateway chose Enbridge's 2010 in-line inspection data set for Line 4 (from the Bethune Station to the Regina Terminal) as an appropriate analog for the proposed oil pipeline, since Line 4 was constructed in 1999 and has a fusion bonded epoxy coating. The modelling results showed that measureable corrosion failure probabilities were reached after 11 to 20 years of simulated unmitigated operation for the range of pipe wall thicknesses proposed for the project. Full-bore rupture failures due to external corrosion were not predicted to occur between regular in-line inspections, when corrosion rates would be assessed and the corrosion mitigated, as appropriate.

Northern Gateway said that modern pipelines are built to limit corrosion infringement through high-quality metallurgy, pipe manufacturing processes, welding materials and techniques, modern fusion bonded epoxy coatings, and numerous pipeline integrity provisions including regular internal magnetic flux leakage inspections. Northern Gateway said that, as a result, the loss of containment due to corrosion and environmentally-assisted cracking is virtually eliminated.

Northern Gateway said that protective coatings would be the primary external corrosion control measure for the oil and condensate pipelines and that cathodic protection would be the secondary control measure.

Views of the Panel

As discussed in Section 5.5.2, external corrosion is a frequent cause of pipeline leaks and ruptures. A pipeline's coating is the principle measure by which external corrosion is prevented. Through Northern Gateway's compliance with the Panel's various conditions, there is likely to be minimal external corrosion on the pipelines. The Panel finds that the risk related to external corrosion would be well managed and monitored.

5.12.4 Third party damage

Northern Gateway's semi-quantitative risk assessment identified third party damage as one of eight threats relevant to the proposed pipelines. Northern Gateway said that, when combined with the other threats, third party damage emerges as a dominant contributor to the overall failure frequency.

Northern Gateway said that third party damage can be established as the product of two independent variables: the frequency of incurring a hit by heavy equipment, and the probability of failure given such a hit. It said that the probability of failure can be determined as a function of pipe design and material properties. Northern Gateway referred to research indicating that approximately 25 per cent of third party damage failures result in rupture. The frequency of impact can be characterized in terms of the following damage prevention factors:

  • land use type;
  • one-call system availability and promotion;
  • pipeline marker sign placement frequency;
  • using buried marker tape at crossings;
  • third party requirements regarding notification of intent to excavate;
  • patrol frequency;
  • response time for pipe location requests;
  • pipeline locating methods used;
  • pipeline marking methods used; and
  • depth of cover.

Northern Gateway said that the potential for strikes and damage to any-sized pipeline increases with human activity, such as excavation, oil and gas activity, and road works. Proximity to urban areas and settlements or to commercial operations also increases the potential for third party damage. Northern Gateway said that, typically, ruptures caused by third party damage would only result from a strike by a large excavator. Of the factors that would affect the probability of a strike by a large excavator, Northern Gateway identified land use type as a key factor in the third party damage model because it defines the overall frequency of excavation on a pipeline right-of-way.

Northern Gateway included the likelihood of failure due to third party damage in its overall risk ranking for each kilometre-long segment of the oil and condensate pipelines. It said that, although the likelihood of failure from third party damage is higher for the condensate pipeline than the oil pipeline due to the different wall thicknesses, the consequence of a failure is less for the condensate pipeline than the oil pipeline. It said that the condensate pipeline's risk ranking was generally calculated as being the same or lower than that of the oil pipeline on a kilometre-by-kilometre basis. Northern Gateway said that European (EGIG) and American (PHMSA) databases show no third party damage failures for any onshore pipeline with wall thicknesses greater than 15 and 16 millimetres, respectively. The proposed oil and condensate pipelines would have minimum wall thicknesses of 19.8 and 7.5 millimetres, respectively.

Views of the Panel

There is a potential risk to the pipelines from third party damage. For this project, the Panel is satisfied that Northern Gateway would adequately mitigate the risk of a rupture caused by third party damage to the oil pipeline by using techniques specified in regulations (e.g., pipeline markers, one-call systems, and depth of cover), particularly since its wall thickness makes it highly resistant to rupture from this threat. The condensate pipeline, with a proposed minimum wall thickness of 7.5 millimetres, would be more susceptible to third party damage. The Panel agrees with Northern Gateway's assessment that the condensate pipeline's overall rupture risk ranking is lower than that for the oil pipeline on a kilometre-by-kilometre basis due to the lower consequence associated with a condensate pipeline rupture, rather than a lower rupture probability.

Due to the potential contribution of third party damage to the overall failure frequency of the pipelines, the Panel requires Northern Gateway to assess and report on additional protective measures for the condensate pipeline in proximity to areas of higher public population and activity (near the Whitecourt casino, Burns Lake, and Kitimat).

5.12.5 Material and manufacturing defects

Northern Gateway said that material defect failures are a result of the presence of pipe body defects or seam weld defects. Northern Gateway's approach to estimate the frequency of occurrence used a baseline failure frequency derived from industry failure statistics for over 274,000 kilometres (170,000 miles) of hazardous liquid pipelines in the United States between January 2002 and December 2005. These statistics, collected by PHMSA, included both leaks and ruptures, and were modified to account for modern pipeline materials, design, and installation.

Northern Gateway said that the United States data contained 19 failures attributed to material defects, which equates to a failure frequency of 1.7 × 10−5 failures per kilometre-year. Northern Gateway's analysis of the data found that modern pipelines had fewer material defects that resulted in leaks and ruptures, and only 2 of the 19 failures were on large-diameter pipelines. Northern Gateway estimated the failure likelihood for a full-bore rupture to be 3 × 10−6 failures per kilometre-year.

Views of the Panel

One of the Panel's potential conditions was to require Northern Gateway to prepare and file with the National Energy Board a project-specific quality management plan, before materials, equipment, etc., were procured. Northern Gateway requested that the condition be limited to the manufacture of major components for the pipelines (including all associated facilities to be installed along it) and the Kitimat Terminal.

A quality management plan is essential for reducing failures caused by material and manufacturing defects. In addition to the National Energy Board Onshore Pipeline Regulations' requirements for Northern Gateway to have a quality assurance program in place, the Panel requires Northern Gateway to file its project-specific quality management plan for National Energy Board approval before manufacturing pipe and major components.

5.12.6 Construction defects (welding and installation)

Northern Gateway said that construction defect failures are failures attributed to construction or installation defects such as girth and fillet weld defects and pipe body failures from dents and gouges. Northern Gateway used the PHMSA database to estimate the frequency of failure due to construction defects, as it did for its analysis of material and manufacturing defect frequency.

Between January 2002 and December 2005, three sub-causes were related to this major threat category. These were:

  • pipe body failures caused by defects such as dents (16);
  • butt weld failures (15); and
  • fillet weld failures (9).

Northern Gateway said that, together, these 40 failures represent a failure frequency of 3.7 × 10−5 failures per kilometre-year. Northern Gateway used this value as the baseline failure frequency for construction defects. Its review of the construction defect failure statistics varied by decade of construction. Newer pipelines had a normalized incident rate that was 60 per cent of the pipeline infrastructure as a whole. To account for this effect, Northern Gateway used an adjustment factor of 0.60 when calculating the construction defects failure frequency. This resulted in a failure likelihood of 2.2 × 10−5 failures per kilometre-year. Northern Gateway said that, in the absence of some large-scale outside force (e.g., a landslide), these defects fail by a leak mechanism, rather than by a rupture. It said that the probability of a full-bore rupture is negligible. It said that this was consistent with the findings of a review of failure incidents from the PHMSA leak database related to construction defects.

Views of the Panel

The Panel is not convinced that Northern Gateway's 0.60 adjustment factor was justified. Construction defects, such as dents, on the older pipelines may have failed as a result of fatigue rather than from a large-scale external force such as a landslide, and the loading cycles for the newer pipelines may not have been sufficient to result in failure. While the failure frequency for new pipelines may not be as low as Northern Gateway suggested, the Panel is of the view that the risk may be reduced by inspections that target pipe body defects. In order to verify that dent defects are adequately identified and addressed, the Panel requires Northern Gateway to complete a high-resolution caliper inspection within 6 months after starting operations. The Panel also requires Northern Gateway to investigate all dents greater than 2 per cent of the pipe's outside diameter, to ensure they are free of gouges and are not associated with a weld. Since 100 per cent of all circumferential welds are subject to non-destructive examination and a pressure test, the majority of field welds would be verified.

5.12.7 Incorrect operations

Incorrect operations failures are related to a failure to follow set procedures during pipeline operations. Northern Gateway estimated the frequency of occurrence for this threat by analyzing the baseline failure frequency derived from the PHMSA industry failure statistics. It modified this value with an adjustment factor to account for modern pipeline materials, design, and installation practices. The adjustment factor was derived from a questionnaire developed by Dynamic Risk Assessment Systems Inc. and administered to Enbridge operations and other subject matter experts during a threat assessment workshop. The questionnaire covered topics intended to gauge the expected performance of Northern Gateway operations in terms of the causal factors of failure related to incorrect operations. The methodology for assigning the adjustment factor based on the questionnaire results was derived from API RP 581 – Risk-Based Inspection Technology.

Northern Gateway said that 61 failures were attributed to incorrect operations, which equates to a failure frequency of 5.607 × 10–5 failures per kilometre-year. Northern Gateway determined the final adjusted failure frequency to be 1.828 × 10–5 failures per kilometre-year.

To estimate potential spill outcomes associated with incorrect operations, Northern Gateway found that 10 of the 61 failures occurred on pipelines over 508 millimetres in diameter. None of these resulted in a pipeline rupture. As a result, it said that the probability of incurring full-bore failures related to incorrect operations was negligible.

Views of the Panel

The Panel finds that Northern Gateway's procedures and training programs address the potential failure to follow set procedures during pipeline operations. Northern Gateway's system implementation would be subject to National Energy Board compliance audits over the course of project operations.

5.12.8 Equipment failure

Equipment failures encompass the failure of non-pipe components and equipment, such as pumps, seals, valves, and flanges. With the exception of block valves and other equipment along the right-of-way, these failures occur at stations. Northern Gateway's approach to estimate the frequency of occurrence for this threat used a baseline failure frequency derived from PHMSA failure statistics, modified by an adjustment factor to account for modern pipeline materials, design, and installation practices.

The failure incident data for four sub-causes related to this threat category is as follows:

  • ruptured or leaking seal or pump packing (64 failures);
  • component failure (45 failures);
  • control or relief equipment malfunction (45 failures); and
  • stripped threads (30 failures).

Northern Gateway said that the combined 184 failures over the analyzed 4-year period represent a failure frequency of 1.7 × 10-4 failures per kilometre-year. No full-bore ruptures associated with this threat were identified. Northern Gateway considers the probability of incurring full-bore ruptures on the proposed pipelines due to this threat to be negligible.

Views of the Panel

With the exception of mainline block valve sites, equipment failure incidents generally occur in stations and terminals. Northern Gateway committed to have all stations and terminals manned by trained personnel at all times and to have systems in place to contain released product within station property. The Panel is satisfied that Northern Gateway would appropriately mitigate this risk. The Panel finds that Northern Gateway's commitment to have facilities manned by trained personnel 24 hours per day is a proactive and precautionary mitigation measure to minimize spills and limit their potential effects.

5.12.9 Geohazards

A geohazard is a threat from a naturally-occurring geological, geotechnical, or hydrotechnical process or condition that may lead to damage. Northern Gateway said that, in the case of this project, damage is considered to be a loss of containment of the product in a pipeline. A geohazard may be triggered by natural or anthropogenic causes.

Northern Gateway said that geohazards were one of the primary considerations in determining the project's feasibility, as well as the proposed route and preliminary design. The project would cross six physiographic regions, including regions with mountainous terrain, geohazards, and areas known to have potential acid rock drainage. It would also involve safely constructing and operating the Kitimat Terminal in an area known to be subject to seismic activity.

Northern Gateway said that it has done a significant amount of work to identify, understand, and assess the risks associated with geohazards along the pipeline route and at the Kitimat Terminal. It said that it recognized that there is more work to be done.

In its application, Northern Gateway considered:

  • deep-seated slides;
  • shallow- to moderately-deep slides;
  • rock falls and rock toppling;
  • debris flows;
  • avalanches;
  • sedimentation and erosion;
  • karst;
  • acid rock drainage;
  • seismicity;
  • marine clays;
  • tsunamis; and
  • associated standard mitigation measures.

Northern Gateway provided preliminary geotechnical considerations and recommendations, and acknowledged that it would undertake further investigations during detailed engineering for design and construction.

Northern Gateway said that its semi-quantitative risk assessment incorporated a quantitative geohazard assessment (QGA). The quantitative geohazard assessment focused on geohazards with the potential to cause a loss of containment. The assessment extended as far from the proposed 1-kilometre-wide route corridor as was necessary to make sure that all applicable geohazards were assessed. Assessed geohazards included:

  • avalanche;
  • avulsion;
  • debris flow;
  • lateral migration;
  • lateral spreading;
  • slide (shallow to moderate);
  • deep-seated slide;
  • rockfalls; and
  • scour.

For each geohazard, the quantitative geohazard assessment considered mitigation options to reduce the potential for it to occur. This included hazard-specific programs such as:

  • an avalanche control program;
  • surface water management;
  • construction techniques or structures such as berms, rock anchors, slope grading, or rip rap;
  • routing or location refinements, such as routing higher on alluvial fans; and
  • avoidance by re-route.

The quantitative geohazard assessment also considered the ability of the pipeline to withstand the imposed effects of a geohazard that may cause a loss of containment. Northern Gateway said that mitigation options to reduce pipeline vulnerability to loss of containment included:

  • heavy wall pipe;
  • concrete-coated pipe;
  • increased depth of cover;
  • trenchless crossing methods;
  • routing around or under a geohazard;
  • deflection berms; and
  • avoidance by re-route.

Northern Gateway said that it would update its geohazard assessments and mitigation options as the project evolves.

Northern Gateway committed to carry out additional geohazard assessments during detailed engineering and to acquire more LiDAR data for the pipeline route's entire length. It also committed to initiate discussions with expert groups and federal and provincial agencies for the purpose of creating an independent geohazard working group.

Northern Gateway filed an updated semi-quantitative risk assessment with Route Revision V to reflect a number of changes to the design basis and route. For example, Northern Gateway identified a major re-route in the Morice River area to move the pipelines up to 3.5 kilometres south of the Route U alignment. This reduced the number of geohazards encountered and reduced the number of spill trajectories that may directly reach the Morice River. Northern Gateway said that its commitments to increase wall thickness, conduct additional geotechnical assessments, and increase the number of valves allowed it to reduce, by almost one-half, the risk of a full-bore rupture along the pipeline route.

Northern Gateway said that it undertook a conser-vative and cautious approach with respect to geo-hazards. It said its approach was to avoid geohazards where possible and, where they cannot be avoided, mitigate and design for the potential maximum effect of the geohazards. For example, Northern Gateway's geotechnical experts said that the proposed landslide mitigation is based on the assumption that landslides would be triggered, not that they might be triggered, allowing for the fact that weather and climate change can be variable.

During final argument, a number of parties raised concerns that Northern Gateway did not adequately assess and characterize geohazards. The Province of British Columbia was concerned that Northern Gateway's assessment of existing and potential geohazards along the pipeline route was not complete, and that further investigations were required. It said that, since not all geotechnical hazards had been identified in the completed investigations and comprehensive investigations would not be done until the detailed design phase, Northern Gateway has only a rough idea of the measures that may be used to mitigate hazards that may be encountered. The Haisla Nation was concerned that geotechnical hazards and terrain stability assessments were incomplete and that Northern Gateway had not yet acquired detailed LiDAR data. The Coalition argued that it was not clear how Northern Gateway could identify technically- and economically-feasible mitigation measures when its geohazards identification and assessment was not yet complete.

In response to the concerns raised about insufficient geohazard information, Northern Gateway said that it is doing what is right by committing to a rigorous program to manage geotechnical risk and acquire additional data, such as LiDAR data, as it proceeds.

Views of the Panel

The Panel is of the view that Northern Gateway's precautionary approach regarding geohazards is consistent with good engineering practice. The Panel finds that Northern Gateway's conservative assumption that geohazards would be triggered ensures that mitigation would be in place for all identified geohazards, or that they have been avoided by routing around areas of concern.

The Panel is satisfied that Northern Gateway recognizes that more work remains to be done with regards to understanding and predicting geohazards. This includes acquiring additional information, such as LiDAR data, and involving other experts in geohazards assessment, mitigation, and monitoring.

The Panel requires Northern Gateway to develop and file for National Energy Board approval a final Geohazard Assessment, Mitigation, and Monitoring Report. This project would benefit from input from other experts on this topic. The Panel requires that this final report include any reports from the independent geohazard working group that must be comprised of geohazard specialists from various organizations, including governments, local experts, and Northern Gateway's consultants.

5.13 Post-construction monitoring and inspections

The National Energy Board requires each regulated company to establish, implement, and maintain a management system that, among other things, applies to all company activities involving the design, construction, operation, and abandonment of a pipeline. As part of its management system, each company is required to:

  • establish and implement a process for identifying and analyzing all hazards and potential hazards;
  • establish and maintain an inventory of identified and potential hazards;
  • establish and implement a process for evaluating and managing risks associated with identified hazards, including risks related to normal and abnormal operating conditions; and
  • establish and implement a process for developing and implementing controls to prevent, manage, and mitigate identified hazards and risks, and for communicating those controls to anyone exposed to the risks.

Management system requirements apply to post-construction monitoring, including inspections and audits. From an engineering perspective, the National Energy Board has previously described monitoring as the regular observation of pipelines and facilities (e.g., through surveys, patrols, inspections, testing, and instrumentation) to verify that their operation is within defined parameters, with the goal of identifying any issues or potential concerns (e.g., pipeline integrity, geohazards, erosion, and security) that may compromise the protection of the pipelines and facilities, property, persons, and the environment.

The National Energy Board requires companies to conduct inspections on a regular basis. It also requires companies to conduct audits at a maximum interval of 3 years. These activities assess whether their pipelines are designed, constructed, operated, and abandoned in compliance with applicable parts of the National Energy Board Act, the National Energy Board Onshore Pipeline Regulations, as well as with the terms and conditions of any National Energy Board-issued certificates or orders. The objective is to ensure the protection of property and the environment, and the safety of the public and company employees.

5.13.1 Integrity management

Northern Gateway said that integrity management entails risk identification and assessment. The results of the integrity assessment would be used to prioritize maintenance activities or projects and the activities would be formalized in various integrity management programs. Each program would use documented policies, procedures, and practices and would confirm the operational reliability of all system components including the pipelines, pump stations, tank terminal and marine terminal piping, and tanks.

5.13.1.1 Pipeline integrity

Northern Gateway said that its pipeline integrity program's primary goal is to prevent leaks and ruptures caused by pipeline deterioration. Northern Gateway would monitor its pipelines to identify defects that may occur, so that remedial action can be taken in a planned approach that would realize the integrity management program's objectives. Northern Gateway said that, by applying risk-control measures over the pipelines' lifespan, a constant base integrity level would be maintained. Northern Gateway described three integrity management activities related to the pipeline integrity program: prevention programs, monitoring programs, and mitigation programs.

Prevention programs would include reviews of pipeline design, construction, and operations; developing construction practices and material specifications; and incorporating quality assurance or quality control measures.

Monitoring programs would monitor corrosion, cracking, and other defects that may cause pipeline deterioration. Techniques to monitor pipeline integrity and assess operational data would include:

  • cathodic protection monitoring;
  • in-line inspections to locate and measure the size of any defects;
  • investigative excavations to assess anomalies and obtain data on coating condition and soil characteristics; and
  • slope stability monitoring.

Northern Gateway said that it would have mitigation programs in place to manage risks posed by pipeline deterioration. It said that it would address anomalies not meeting fitness-for-service acceptance criteria using sleeve repairs, pipe replacements, pressure reductions, and rehabilitation or inhibitor injections.

Northern Gateway said that its slope stability monitoring program would include monitoring sensitive slopes for ground movements and assessing the potential effects of these movements on pipeline integrity. It speculated that this monitoring might include instrumentation, regular visual inspections, pipe assessments, or some combination of these. It would implement remediation or reconstruction projects, or both, to confirm the affected pipeline's ongoing integrity.

Northern Gateway said that its pipeline integrity management structure would include its risk-based integrity management program that addresses the potential for, and the consequences of, a pipeline rupture. It would establish a geohazard management program for the necessary areas identified during detailed engineering, including the Kitimat Valley. This would include collecting weather data, aerial and satellite surveillance, continuous slope stability monitoring, and periodic on-site assessments of critical areas.

Northern Gateway said that it would conduct comprehensive inspections following pipeline construction and commissioning. This includes:

  • baseline inspections with high-resolution in-line inspection tools, including GEOPIG™, ultrasonic corrosion, ultrasonic cracking, and magnetic flux leakage (MFL);
  • surveys of pipeline coating integrity (using "above-ground" survey techniques); and
  • strict thresholds for excavation and repair of identified pipeline anomalies.

Northern Gateway said that, because the Kitimat Valley is deemed to be a high consequence area, it would perform the following inspection procedures that are over and above routine Enbridge integrity management processes:

  • a GEOPIG™ during the first year of operations;
  • crack detection within the first 2 years of operations;
  • corrosion magnetic flux leakage (MFL) within the first 2 years of operations; and
  • ultrasonic wall measurement during the first 2 years of operations.

In addition to specific plans for high consequence areas (e.g., the Kitimat Valley) that would involve numerous in-line inspection surveys within the first 2 years of operations, Northern Gateway said that it would increase the frequency of its in-line inspections across the entire pipeline system by a minimum of 50 per cent over and above its current standards.

5.13.1.2 Facilities integrity

Northern Gateway said that it would implement facility-based integrity programs that would be administered by the project's program coordinators, engineers, and regional operations personnel. Northern Gateway said that there would be an inspections program for all components of the marine facilities at the Kitimat Terminal. It would complete periodic inspections throughout each year, with extended inspections being conducted whenever the periodic inspections indicated the need. Special inspections would be performed before and after maintenance and repair work. All terminal piping would be above ground and its inspection would be included as part of regular maintenance practices. Northern Gateway would visually inspect piping to confirm there is no corrosion, leakage, or other evidence indicating that it is not in good condition.

Northern Gateway said that tanks would be subjected to regular inspection protocols at intervals specified by API standards. These inspections would assess wall thickness, coating integrity, tank base settlement, and welds. Northern Gateway would regularly monitor tank cathodic protection for its functionality. The tank design would include a leak detection system to monitor for leaks below the tanks.

Northern Gateway said that it would inspect and cycle valves in accordance with industry standards as part of regular maintenance practices. It would inspect and test safety systems on a regular basis to confirm they are in good working order. Northern Gateway would establish inspection and testing frequency in the site operating and maintenance procedures.

Northern Gateway said that it would staff all of its pump stations 24 hours per day, 7 days a week, for on-site equipment monitoring and security, rapid response, and, ultimately, to further ensure the safety of the public and protection of the environment.

Views of the Panel

Northern Gateway has committed to carry out certain inspection procedures for the Kitimat Valley area, which it indicated are over and above routine Enbridge integrity management processes. The Panel requires Northern Gateway to apply these procedures along the entire pipeline route, regardless of the rupture likelihood.

The Panel requires Northern Gateway to conduct baseline inspections and verification of dents and coating condition. The Panel is of the view that Northern Gateway's approach to post-construction monitoring is appropriate for the project.

Summary views of the Panel

The Panel notes that there is the potential of unforeseeable naturally occurring events such as landslides, earthquakes, and tsunamis, that add uncertainty and risk. The Panel finds that such risks are likely to be inherent in projects of the scope of the Enbridge Northern Gateway Project. Risk posed by these types of natural events cannot be precisely known, measured, or completely prevented. Based on the evidence, the Panel finds that Northern Gateway has taken a proactive approach in the incorporation of baseline data into its initial project design elements to mitigate risks from these types of natural events. The Panel finds the Northern Gateway's approach to further understand geohazards would be enhanced by their commitment to work with an independent geohazard working group. The Panel finds that Northern Gateway's semi-quantitative risk assessment methodology is a proactive approach to managing potential threats to pipeline integrity at the design stage of a project. The Panel finds that Northern Gateway has taken all reasonable steps to design a project that would minimize risks of project malfunctions and accidents due to naturally occurring events.

The proposed pipelines and terminal would incorporate new, proven technology and materials that were not available in the 1970s or earlier. Since then, pipeline technologies, materials, codes, and regulations have been developed as a result of lessons learned from previous failures, and research is ongoing to find ways to improve pipeline performance. The Panel finds that Northern Gateway's valve optimization and overland spill modelling is a sound approach to minimizing consequences should failures occur. As a result of these innovations, historical industry failure statistics may not have been the most suitable basis for estimating future failure rates for this project.

Northern Gateway has taken a precautionary approach by showing a commitment to improve performance, and, in some cases, to go beyond applicable regulations, codes, and technologies. Northern Gateway's intention to implement new complementary leak detection technologies, to improve its ability to detect leaks, is an example of this. The Panel recognizes Northern Gateway's commitment to change its corporate culture to improve its pipeline integrity programs.

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Date Modified:
2013-12-19