Topics of Importance Maintaining the Fitness of our Systems and Leak Detection

Our Spill Performance

The following is an overview of our LP, GPP&ES and GD spill performance.

Liquids Pipelines

In 2015, LP delivered more than 2.8 billion barrels of crude oil from where it is produced to refineries in Canada and the U.S. During this period, LP reported 45 commodity (crude oil and natural gas liquids) spills and leaks on its systems, totaling 279 barrels.

Of this total, one incident was significant, meaning that it was a reportable commodity spill or leak that was greater than 100 barrels (15.9 cubic meters) or entailed clean-up costs of $1 million or more.  In 38 of the incidents, 264 barrels of the spilled product were completely contained within LP’s facilities and cleaned up with little or no environmental impact. In seven incidents, 15 barrels were spilled on LP’s rights-of-way or outside its properties.

In all cases, we reported the spills to regulators, responded rapidly and safely cleaned up the impacted areas.

The total number reported indicates the number of spills that LP was required to report to regulators in all jurisdictions, and is based on reporting criteria that the Transportation Safety Board of Canada introduced in 2014.



Liquids Pipelines
Volume of Total Reportable Spills Compared with Total Delivery Volume

From 2006 to 2015, LP delivered 17.2 billion barrels of crude oil and liquids with a safety record of 99.9995 percent. Most of LP’s spills were less than a barrel and occurred inside pump stations (on-site) where any spilled oil was readily contained and recovered without entering the natural environment.

Prior to 2012, some of these spills were of non-commodity products (such as brine or hydraulic fluid) that were not the result of loss of containment of the pipeline commodities being transported.


Total Number of Spills (On-site / Off-site)1,2

Total Spills Volume (barrels) (On-site / Off-site)1,2

Total Annual Delivery Volume2,3 (barrels)

Percentage of Annual Delivery Volume Safely Delivered (%)

Percentage of Annual Delivery Volume Safely Delivered (%) excluding On-site1 Spill Volumes


62 (54 / 8)

5,434 (3,177 / 2,258)





59 (52 / 7)

13,756 (902 / 12,854)





80 (72 / 8)

2,681 (2,587 / 94)





89 (83 / 6)

8,353 (6,524 / 1,829)





80 (61 / 19)

34,122 (2,710 / 31,412)





58 (50 / 8)

2,284 (637 / 1,646)





77 (65 / 12)

10,178 (6,939 / 3,239)





114 (99 / 15)

4,298 (2,656 / 1,642)





745 (71 / 3)

2,921 (2,807 / 114)





45 (38 / 7)

279 (264 / 15)





738 (645 / 93)

84,306 (29,204 / 55,102)


99.9995 (average over 10 years)

99.9997 (average over 10 years)

1     “On-site” refers to spills that occurred at our facilities. In some cases, however, spills that we classify as on-site may result in product leaking off-site. Regardless, most on-site spills are completely contained within our facilities and are quickly cleaned up with minimal or no environmental impact. “Off-site” refers to spills that occurred on our rights-of-way or outside our property.

2     Enbridge entities included: Enbridge Canadian Mainline System (including Line 9); U.S. Mainline Lakehead System, Toledo Pipeline, Enbridge Pipelines (Ozark) LLC (including the Cushing Central Pipeline, Cushing Merchant Tankage, Cushing North Pipeline, Cushing South Pipeline, Eldorado Pipeline and West Tulsa Pipeline); Enbridge Pipelines (Athabasca) Inc. (including the Athabasca Tank Farm, Athabasca Pipeline, the Mackay River Pipeline, Waupisoo Pipeline, Woodland Pipeline, Wood Buffalo Pipeline and Norealis Pipeline); Hardisty Contract Terminal; Enbridge Pipelines Inc. (Midstream); North Dakota Pipeline Company; Enbridge Pipelines (Bakken) LP; Enbridge Pipelines (Norman Wells) Inc.; Enbridge Spearhead (CCPS Transportation LLC); Enbridge Southern Lights; Hartsdale Pipeline; Hardisty Cavern, Flanagan South Pipeline, Enbridge Pipelines Saskatchewan Inc., and North Dakota Pipeline Company and Eddystone Rail (facility, only fills rail cars). We do not track volumes for Line 8 we contract out its operations to Imperial Oil Limited. We calculate Line 8 volumes based on monthly invoicing to Imperial Oil for 14,800 cubic meters.

3     Volume reported is gross delivery volume.

4     In our CSR reports prior to 2012 we included non-commodity (e.g., brine, hydraulic fluid) spills in our LP spills statistics. For 2012 and in all future CSR and sustainability reports, we are reporting only spills of commodities (i.e., hydrocarbon products such as crude oil transported through an Enbridge pipeline) in our LP spills statistics. We have not adjusted previous years’ statistics to reflect this change. 

5     Indicates the number of spills that LP was required to report to regulators in all jurisdictions in 2014. If the Transportation Safety Board of Canada had not changed its reporting requirements on July 1, 2014, we would have reported 100 spills with a volume of 2,943 barrels. 

Gas Pipelines, Processing & Energy Services

GPP&ES transports more than 4.2 billion cubic feet of natural gas every day—totaling more than 1.5 trillion cubic feet a year—as well as natural gas liquids such as propane and butane.

In 2015, GPP&ES had nine federally reportable liquids spills totaling approximately 14 barrels, and one federally reportable gas release totaling about 1.11 million standard cubic feet.  Of the total volume of liquids spilled, GPP&ES spilled 13 barrels at six of its facilities or rights-of-way, and less than one barrel off site of our property.  It reported no significant (Tier I) spills, which GPP&ES defines as spills that meet the following criteria:

  • 50 cubic meters (90,000  lb. or 310 barrels) of oil or more,
  • 1,000 lb. of H2S or more,
  • 50,000 lb. of natural gas or more, or
  • 50,000 lb. of natural gas liquids or more.

The liquids spills and natural gas releases that GPP&ES reports include commodity spills, leaks and releases that are large or significant enough to require us to formally notify a federal regulatory authority.

While, beginning in 2013, LP stopped reporting spills, leaks and releases of non-commodities (e.g., brine, hydraulic fluid, drilling fluid, lube oil), in Enbridge’s CSR and sustainability reports, GPP&ES continues to report on spills and releases of these commodities.





Gas Distribution

GD provides reliable natural gas service to more than two million customers in Ontario, Quebec, New Brunswick and New York State. In 2015, GD delivered more than 422.3 billion cubic feet of natural gas to its customers. During that time, it reported the following releases, none of which were significant. GD defines significant releases as those that management deems to be major environmental events, or that cause: environmental damage to at least one hectare (2.5 acres) of land; death or damage to multiple fish, birds or wildlife; permanent or widespread damage to wildlife habitat; and that result in remediation costs that exceed $25 million.

Number of Natural Gas Releases Caused by First- or Second-Party Damages through Tier 1 Incidents – In 2015, GD reported no natural gas releases that were caused by first- or second-party damages to its pipelines or facilities. First-party damages are mechanical damages that are caused by GD’s employees, while second-party damages are mechanical damages that are caused by its contractors. GD defines first- and second-party damages as damages that result in:

  • unplanned and uncontrolled releases of more than 150,000 cubic meters of natural gas,
  • unplanned and uncontrolled releases of odorant that directly result in an incident outcome,
  • overpressure exceeding 20 percent maximum operating pressure, or
  • releases of carbon monoxide that directly result in an incident outcome.


Number of Natural Gas Releases Caused by Third-Party Damages – GD reported 1,476 natural gas releases caused by third-party damages, which are incidents of mechanical damage to its pipelines caused by others, often landowners, municipal workers or excavators working for others.


GD’s largest operational threat is third-party damage to its natural gas pipeline infrastructure. Preventing damage improves worker and public safety, as well as the fitness of GD’s gas distribution assets.

The number of damages that occur on natural gas pipeline infrastructure strongly correlates to the amount of construction activity being undertaken in a particular area. As such, one of GD’s key damage prevention measures is to provide the location of related underground infrastructure to excavators before they dig. By providing this information, GD has reduced both its normalized number of damages per thousand locate requests and its absolute number of damages. In 2015, it had 2.41 damages per 1,000 third-party locate requests.


Number of Significant Natural Gas Releases Caused by Planned Venting – GD reported four significant natural gas releases that were the result of its purposeful venting of natural gas (planned venting). Although GD endeavors to minimize its release of natural gas and other GHGs, at times, it must conduct planned venting such that it can safely perform maintenance work of its storage facilities and pipelines.


GD is not able to reliably track the volume of any of its natural gas releases. As such, it reports only on the number of releases it experienced.

GD does estimate the volume of its GHG emissions and reports the volumes elsewhere in this report. For more information, please see the Environment & Climate Change section of this report.  [provide link]

How LP’s Spill Performance (Frequency and Volume) Compares with the Rest of Industry 

Canada – While the Transportation Safety Board of Canada (TSB) and the National Energy Board (NEB) both publish data on pipeline incidents, neither publishes the total length of active liquid pipelines. Because we would require the total length of active liquid pipelines to normalize the data, we are unable to calculate comparable industry averages at this time.

U.S.The following graphs compare LP’s spill performance (frequency and volume) with that of the rest of the industry in the U.S. using incident data from the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) as of November 30, 2015, and PHMSA system length and barrel-miles data for hazardous liquids pipelines for 2009 to 2014.

The graphs apply to hazardous liquids pipelines and include all products under that definition:

  • crude oil,
  • refined and/or petroleum products (non-HVL; liquid at atmospheric conditions),
  • highly volatile liquid (HVL; vapor at atmospheric conditions),
  • fuel-grade ethanol (dedicated system)*, and
  • CO2**.

* We do not have dedicated fuel grade ethanol pipelines.

** We do not operate CO2 pipelines. Mileage and barrel-miles for CO2 pipelines are not included.

For the purposes of the comparison, significant incidents are defined as incidents where any of the following criteria were met:

  • $50,000 or more in total costs, measured in 1984 dollars,
  • HVL releases of five barrels or more,
  • non-HVL liquid releases of 50 barrels or more, or
  • unintentional fire or explosion.

Significant incidents are reportable incidents; however, not all reportable incidents are significant.  Overall, significant incidents account for about 99 percent of the total release volume.

The graphs apply only to incidents that took place on LP’s onshore hazardous liquids pipeline systems.



Significant Spills, Leaks and Releases in 2015

LP experienced one significant spill in 2015, and GPP&ES and GD did not experience any significant spills, leaks or releases.  LP defines significant spills as any reportable commodity spill or leak that is greater than 100 barrels (15.9 cubic meters) or that has entailed clean-up costs of $1 million or more. One barrel of oil is equal to approximately 159 liters or 42 U.S. gallons.

Cromer, Manitoba - On October 15, 2015, approximately 188 barrels (30 cubic meters) of crude oil leaked from piping at our LP terminal near Cromer, Manitoba, while we were removing a blind flange in preparation for a tie-in on a tank line. We contained all of the oil within the tank lot berms.  We notified the National Energy Board and took prompt action. We recovered all free oil and impacted soil and disposed of it in accordance with our waste management plan. We conducted an internal root-cause investigation and determined the direct cause of the release to be an isolation valve that had been partially open. As a result of the investigation, we have provided additional training to workers for equipment lockout procedures and are applying the lessons we learned to prevent similar events from occurring in the future.

Investments in Maintaining the Fitness of our Systems and in Leak Detection

Since our major 2010 spill in Marshall, Michigan, LP has significantly increased its investments in programs and technologies that help it maintain the fitness of its systems and leak detection.

As the following pie charts show, LP increased its investment in these areas from $130,000 per billion barrel-miles of pipeline over the 2005 to 2009 period to $880,000 per billion barrel-miles over the 2010 to 2014 period. LP is forecast to spend about $430,000 per billion barrel-miles on system integrity programs for 2015 to 2019.

We have normalized our expenditures by billion barrel-miles by summing up the distance that LP ships each barrel of crude on its system in a given year. Normalizing numbers in this way makes it possible for us to fairly compare what we spend on maintaining the fitness of our systems and on leak detection over time, given that our pipeline system has been growing almost continually over the past several years.

After our Marshall spill, LP significantly increased its efforts to understand the condition of its pipelines and to mitigate any discovered threats. Compared to the 2005 to 2009 time period, the 2010 to 2014 time period reflects LP’s increased programs, projects and initiatives. These investments have resulted in two key outcomes:

  • LP has advanced its systems (technology, analysis and process safety) such that they are a leading example of fitness, safety and reliability management for liquids pipelines, and
  • LP reached a target safety level by the end of 2014.

Over the next five-year time period (2015 to 2019), LP’s commitment to maintaining the fitness of its systems and to effectively detecting leaks will not decrease. Advancements in predictive (reliability) modeling, data analysis and improved efficiency in carrying out these activities will enable LP to continually enhance the safety and fitness of its systems while optimizing expenditures. This optimization is reflected in the following charts, which show comparable numbers of inspections and scale of analytics to the previous time period.


In addition, LP has more than doubled the number of employees and contractors who are dedicated to maintaining system fitness over the last five years, from nearly 80 positions in 2010 to more than 160 positions at the end of 2015. Similarly, LP has increased the size of its team dedicated to leak detection and pipeline control, from more than 130 positions at the beginning of 2011 to more than 230 at the end of 2015. Some of this growth is due to LP’s overall growth, but part of it is due to its increased focus on maintaining system fitness, leak detection and pipeline control.

Within our GD and GPP&ES business segments, over 110 professionals are dedicated to maintaining the long-term fitness of their systems.

Dollars Spent by LP Canada, LP U.S., GD and GPP&ES on Maintaining the Fitness of our Systems

 (2012 – 2015)

Liquids Pipelines Canada (CAD)

Liquids Pipelines U.S. (USD)

Gas Distribution (CAD)

Gas Pipelines, Processing & Energy Services (USD)

Total (CAD and USD)


$469 million

$624 million

$114.6 million

$15.1 million

$1.2 billion


$900 million

$645 million

$113.9 million

$15.9 million

$1.6 billion


$767 million

$375 million

$124.9 million

$11.7 million

$1.2 billion


$389.7 million1

397.5 million2

$133.3 million

$5 million3

$925.5 million


$4.925 billion4

1 Includes spending totals in Canada of $370 million for LP system fitness programs and $19.7 million for LP leak detection programs.

2 Includes spending totals in the U.S. of $390 million for LP system fitness programs and $7.5 million for LP leak detection programs.

3 A significant portion of GPP&ES’s spending from 2012 to 2014 was on Propylene and Tinsley assets, of which it divested in 2015.

4 Includes Canadian and U.S. dollar amounts.

Improvements to Management Systems

Management systems ensure that we have industry-leading standards, controls and procedures to maintain safe, reliable operations. They also enable employees to execute work consistently across our company.

For LP, the Integrated Management System provides a holistic approach to ensuring that all of LP acts in accordance with internal policies and external regulations through the alignment of strategy, processes, technology and people, thereby improving efficiency and effectiveness.

For GD, the Integrated Management System sets out a governance framework that integrates and documents GD’s core processes, resources, policies and organizational structures. This system is based on a requirements list and on multiple corporate and regulatory requirements to ensure that all appropriate elements were included.

In 2015, our business segments made a number of improvements to their management systems:

  • LP developed and documented the core processes that more clearly define the roles and responsibilities that are required to maintain the fitness of its systems.
  • GD developed and defined its management system structure. In addition, it formally documented its management system requirements and how it is meeting them.
  • In 2015, GPP&ES began implementing an enhanced risk-based inspection software tool for its processing plants. This software tool will house all inspection data for vessels and piping within each plant and will prioritize and schedule inspections based on risk.

Complementing the business segment management systems are our Enterprise Risk Management (ERM) Framework and our Safety Management System Framework, which provide baseline standards to which we expect our business segments to adhere. These frameworks include tools and techniques that the business segments use to effectively manage their risks.

In 2015, we began implementing the two frameworks. We conducted an extensive review to ensure that their components were embedded within LP’s Integrated Management System, and carried out similar review processes in other business segments and groups. This effort will help us reinforce a consistent approach to addressing risks across our organization. For more information, please see the Risk Management section of this report.

Pipeline Inspections and Integrity Digs

Each year we conduct a significant number of pipeline inspections using sophisticated tools that incorporate leading imaging and sensor technology, and that are capable of scanning for features that could indicate potential problems. Our inspections allow us to monitor the physical condition of our pipelines from the inside and outside, and to gather the information we need to keep our systems fit.

In 2015, we completed 194 pipeline inspections—including in-line, hydrostatic, ultrasonic and pressure test inspections—on our crude oil and natural gas pipelines and distribution systems. Over the past four years, we have carried out more than 890 such inspections on our systems.

As part of our program to maintain the fitness of our systems, we also perform integrity digs along our pipeline network. Each integrity dig involves excavating a section of buried pipe so that we can carefully clean it, remove its coating and examine it. If we find a defect, we repair and re-coat it, and carefully backfill the excavation site. In 2015, we carried out 1,575 integrity digs across our systems.

Here are some highlights of our pipeline inspection and integrity dig programs by business segment:

  • LP used in-line inspection tools on 141 runs to inspect more than 10,349 kilometers (6,431 miles) of pipeline, which is about 42 percent of its active system. It also carried out 1,545 integrity digs.
  • GD conducted 31 in-line and ultrasonic inspections on 13.5 kilometers (eight miles) of its higher pressure pipeline. It also investigated and mitigated 30 features, including metal loss, deformation and crack indications. 
  • GPP&ES carried out 14 in-line inspections on 419 kilometers (260 miles) of its U.S. gas and crude oil systems to meet regulatory requirements. It carried out an additional inspection as part of preventative maintenance, and completed 30 integrity digs.

Number of Pipeline Inspections Performed by LP, GD and GPP&ES (2012 – 2015)

Liquids Pipelines

Gas Distribution

Gas Pipelines, Processing & Energy Services






















1 Includes in-line inspections and ultrasonic inspections.

2 Includes in-line inspections, hydrostatic and pressure test inspections.

Right-of-Way Optimization

In 2015, LP implemented a “right-of-way optimization” initiative under which it geographically bundled its integrity digs so as to capitalize on program efficiencies and minimize the number of times it needed to access the land along its rights-of-ways.

Improvements to Operational Reliability

In our drive to enhance operational reliability, we continued to advance new assessment techniques and to develop our system fitness management programs in 2015.

Engineering Analytics

LP is applying engineering techniques from other highly reliable industries, such as the airline and nuclear industries, to enhance the ways it determines the potential of pipeline failures.  In particular, LP has adapted the safety-case method—a highly structured approach that uses probabilistic analysis to assess operating hazards and mitigation plans—for its liquids pipelines. LP is using this technique as an additional way to assess the fitness of its pipelines and the effectiveness of its inspection and damage prevention programs.

Geohazards Assessment

Our liquids pipelines system crosses numerous rivers and widely varying terrain. To protect the integrity of this vast continental system, we closely monitor geohazards (environmental forces such as floods, soil erosion, seismic activity and slope movement), which have the potential to move pipelines, and can result in stresses and strains that could cause pipeline failures.

Since 2012, we have developed a comprehensive geohazard process management program for our liquids pipelines. Over the last four years, this program has involved extensive assessments with geotechnical engineers and other specialists to identify and inspect more than 5,700 geohazard sites, primarily river crossings and slopes. We continue to perform various monitoring activities at these sites, tracking slope movement, measuring pipe strain with strain gauges, and watching for extreme weather events such as floods and earthquakes. In some cases, we must alleviate risk to our pipelines by replacing segments of pipe, remediating high risk slopes or replacing river crossings. Based on risk levels, we have selected a number of sites for annual inspections. In 2015, we inspected more than 2,800 geohazard sites in Canada and the U.S., including slopes and water crossings.

During the year, we also developed an online training course to increase employee awareness about geohazards. To be rolled out in 2016, the course will enable field employees to identify the main geotechnical hazards to our pipelines and to better understand our geohazard management program.

Hydrostatic Testing

In June, 2015, the National Energy Board (NEB) asked us to conduct hydrostatic testing on three segments of our Line 9B Reversal and Line 9 Capacity Expansion project (Line 9) in Ontario and Quebec. On September 30, 2015, the NEB confirmed that the tests we conducted met its criteria and were successful.

Maintaining Facility Fitness

As we increase programs to maintain the fitness of our Mainline system, we are also focusing attention on maintaining the fitness of our facilities.

LP is applying new technologies to screen for defects on facility pipelines that it is not able to detect using in-line inspection devices, or that are difficult to inspect due to the pipe and valve configuration. As part of this work, LP is employing above-ground inspection techniques, including magnetic tomography, to complete preliminary assessments of below-ground piping in facilities for corrosion and crack defects. In 2015, LP successfully used the technology to inspect 13.9 kilometers (8.6 miles) of facility piping, including tank lines, at terminals in Edmonton and Hardisty, Alberta; Stony Beach, Saskatchewan; Cromer, Manitoba; and Sarnia and Westover, Ontario.

LP is also continuing to employ radiographic techniques to screen small-diameter drain-line connections for corrosion in facilities across its system. The technology provides a detailed x-ray image of small diameter lines to detect sediment buildup and corrosion damage.  LP uses the results of these inspections to proactively manage drain lines through cleaning, chemical inhibition or repair.

Along with numerous inspections of above-ground and below-ground piping, LP is nearing completion on the inspection of relief lines throughout the system to ensure that these assets will function properly when needed.

LP also regularly inspects welded oil storage tanks based on American Petroleum Institute (API) requirements. Each year, LP removes approximately five percent of the tanks from service to perform a thorough inspection and refurbishment.

Under Occupational Safety and Health Administration (OSHA) regulations, operators in the U.S. are required to inspect their gas processing equipment, as identified in API codes and recommended practices, every five years externally and every 10 years internally. To comply with these regulations, GPP&ES follows a rigorous schedule to assess the mechanical integrity of its 28 natural gas processing plants, inspecting 20 percent of every plant each year, checking vessels and piping for corrosion, and testing all safeguards. To support these inspections, GPP&ES implemented a plant condition monitoring system in 2015. The new system will allow for a more efficient inspection program by highlighting risk mitigations of pressurized equipment and providing adequate annual scheduling for assessments.

Preventative Maintenance of GD’s Gas Storage Operations

GD’s natural gas storage operation provides it with a critical natural gas load balancing service.  To help ensure the operation’s reliability, GD supports a preventative maintenance program that consists of proactive inspections that are determined by regulatory requirements, vendor warranty or best practices of gas storage assets, and that include required follow-up repairs.  Compression equipment, injection, withdrawal wells, SCADA systems and electrical systems are all included under the scope of the preventative maintenance program.

GD schedules approximately 1,090 preventative maintenance activities each year to ensure that it can proactively identify and repair problems.

Supporting GD’s Cathodic Protection Program

As part of its annual compliance program, GD collects data on the cathodic protection of the steel pipe in its natural gas distribution network.  GD uses the data to assess the effectiveness of its corrosion prevention system against protection criteria.  If the data identify areas of the system that fall below protection criteria, GD’s maintenance crews follow up to investigate the cause and to make any necessary repairs.  Since 2013, GD has implemented efficiencies to speed up the cycle from data collection to repair. As a result, the effectiveness of the corrosion prevention system has improved from 89 percent in 2013 to 94 percent in 2015. 

Fitness for Service of GD’s Customer Assets

GD inspects all customer piping and appliances prior to activating natural gas services.

In addition, as mandated by Measurement Canada, GD completes 60,000 to 90,000 natural gas meter and regulator exchanges each year, during which it inspects its customers’ piping and appliances for safety and compliance with the Canadian Standards Association Natural Gas Installation Code.  GD issues warning tags if its customers’ piping and appliances do not meet safety requirements. If it identifies immediate hazards, it disconnects the natural gas until the issues are resolved by a licensed technician.

In 2015, GD also inspected approximately 20,000 customer homes that it supplies with high-pressure (175 psig) and extra high-pressure (500 psig) gas. During the inspections, it immediately resolved critical safety issues and scheduled follow-up work for non-critical issues.

And, GD routinely inspected customers’ piping and appliances when it responded to emergency or other customer-initiated service calls.

In 2016, GD will begin implementing a Customer Safety and Compliance Quality Management Program as part of Ontario Regulation 212/01 to improve the condition monitoring, mitigation activities and safety associated with customer piping and appliances. This program will fall under GD’s Integrated Management System for Continuous Operational Improvement, the elements for which will include:

  • re-inspections of new and existing appliances,
  • safety and risk studies regarding asset integrity,
  • improved competencies for technicians,
  • engaging the heating, ventilating and air conditioning (HVAC) industry and the Technical Standards & Safety Authority, and
  • enhancing existing standards and policies.

Improvements to Process Safety Management

Another way that we are maintaining the fitness of our systems and increasing the safety of our pipelines is through process safety management.

Process safety incidents typically involve an unexpected integrity failure in a pipeline system or processing facility, often involving a fire, explosion, rupture, or release or leak of hazardous material. These incidents have the potential to injure people and claim lives, impact the environment, and have far-reaching and long-lasting consequences.

To minimize these risks, industry applies a disciplined management approach focusing on prevention, detection, control and mitigation of process safety incidents. This approach involves a comprehensive set of best practices for keeping gas or oil in the pipe, encompassing everything from design and construction through to operation and maintenance of pipelines and facilities. Process safety practices work by integrating the outputs of all departments, so a change in one area will not have an adverse impact somewhere else. By paying close attention to process safety management, we help to ensure operational reliability and protect workers, the public and the environment.

We promote the consistent development of process safety programs across our company through our Joint Business Unit Process Safety Council, which reports to our enterprise-wide Operations and Integrity (OIC) Committee. Through the council, senior leaders from each of our business segments meet monthly to share learnings and implement best practices.

Each business segment has established its own process safety team and is taking steps to incorporate process safety management into day-to-day operations. Some of the areas that they are addressing are:

  • incident investigation procedures,
  • equipment information and standards,
  • controlling changes to prevent unplanned impacts to operational reliability, and
  • process safety hazard assessment and mitigation.

Over the last four years, through the API, we have helped develop an industry recommended practice (API RP 1173) for pipeline safety management system requirements.  The result of substantial industry effort, API RP 1173 provides detailed guidance on how to develop and maintain a pipeline safety management system.  By applying the new recommended practice, pipeline operators are taking important steps to develop a comprehensive, process-oriented approach to safety that emphasizes continual assessment and improvement.

In 2015, LP, GD and GPP&ES conducted a gap analysis to compare their process safety management practices against the new recommended practice. As a result, they have developed action plans for improvement and are building API RP 1173 requirements into their management systems.

Improvements to Leak Detection and Monitoring

Because our core business is to safely transport hazardous materials through a network of pipelines, we continually improve the methods we use to prevent and detect leaks and releases.

LP continues to improve its computational pipeline monitoring (CPM) systems that collect data from strategically located flow meters and pressure and temperature sensors along our pipelines. In 2015, LP carried out development and testing of CPM methods to improve leak detection performance. These methods are expected to enhance LP’s ability to detect smaller leaks reliably and quickly.

In addition, LP has introduced a rupture-detection system to complement its existing leak detection strategy.  The goal of the system is to ensure prompt and consistent detection and response to ruptures (high volume, high flow events). LP has substantially completed phase one of the project and has deployed the rupture detection system on most of its pipelines across Canada and the U.S.  This effort builds on earlier work that LP had conducted through API. In 2014, together with industry, LP participated in the development of an API best practice recommendation on liquids pipeline rupture recognition and response.

In 2015, LP also executed computer-simulated tests to measure its leak detection performance across its entire pipeline system.  It complemented these tests with 15 announced and unannounced fluid withdrawal tests, which enable LP to evaluate the performance of its system and its people to identify further improvements to processes and technology.

GD continually enhances its knowledge of the characteristics of its natural gas distribution system through targeted risk assessments of its assets. In 2015, GD conducted leak surveys on more than 7,300 kilometers (4,530 miles) of distribution mains in the Enbridge Gas Distribution (EGD) franchise area, which equals approximately 20 percent of the EGD system.

Helping to support this effort was GD’s new Leak Survey Management System. This GIS-driven system provides leak survey technicians a visual representation of where the assets to be surveyed are located, identifies their location, enables them to easily capture findings and allows the business segment to track completion of the surveys in a more accurate manner.  In 2015, GD continued to enhance the system to incorporate specialized inspection programs, using it, for example, to manage inspections of residential meter sets against compliance requirements.  GD is now working with 3-GIS LLC to further evolve the system to manage and execute corrosion prevention programs.

Industry Leadership

We continue to shape industry best practices and technology development through industry associations such as:

Here are some achievements that resulted from our involvement in industry associations in 2015:


Over the past four years, in collaboration with API, we participated in the development of a safety management system for the pipeline industry. This recommended practice, known as API RP 1173, was completed and published in 2015, and is designed to build and enhance pipeline safety management practices for the industry.  We are now working with several industry associations, including AGA, AOPL and SGA, to share approaches on how to best implement the new recommended practice.

Crack Management

Through API, we played an instrumental role in developing a new crack management recommended practice. This operational practice will provide guidance to pipeline companies in taking an integrated management system approach to address cracks in liquids pipelines systems.

In-line Inspection Technologies

We have worked with PRCI to complete the NDE-4E project to evaluate the effectiveness of a wide range of in-line inspection (ILI) technologies for liquids pipelines. The foundation for the study was the development of an extensive database of crack inspection data collected from pipeline operators through an industry data mining exercise. The study represents the first known exercise to establish an industry-wide database for ILI technologies and has set a new standard for data mining as a basis for establishing ILI performance metrics. The project report was completed and published in 2015 through PRCI. We sponsored this project and provided leadership from inception to completion.

Joint Industry Partnerships

We have helped to lead two joint industry partnerships focused on external leak detection sensors. Involving a research company and the Alberta and federal governments, the partnerships are evaluating the use of aircraft-mounted sensors and cable-based sensors installed along pipelines.

Peer Review of Gas Distribution Operating Practices

Through AGA, our GD business segment participated in a peer review of leading operating practices among a select number of Canadian and U.S. gas distribution companies. The pilot initiative involved information sharing by industry experts on a range of topics including system integrity, leak detection and damage prevention.

Leadership through Industry Association Working Groups

We are also actively engaged in industry association committees and working groups to advance best practices, new technologies and improve codes and standards. In 2015, for example, experts from our LP Pipeline Integrity and Leak Detection departments participated in more than 40 decisive roles in PRCI, API, AOPL, CEPA and other industry organizations. Our employees also contributed to numerous industry conference presentations and technical articles in an effort to share learnings and experience related to pipeline integrity management and leak detection.

For more information, please see the R&D and Innovation section of this report.