While we were unsuccessful in fully meeting our target to achieve 100 per cent safe operations and zero incidents in 2014, LP reduced its number of total reportable commodity spills from 114 in 2013 to 100 (74 when Canada's Transportation Safety Board's new reporting regulations are taken into account) in 2014. During the same period, LP also reduced the volume of its spills from 4,298 barrels to 2,943 barrels (2,921 when Canada's Transportation Safety Board's new reporting regulations are taken into account).
The following is an overview of our spill performance in LP, GD and GPP.
In 2014, LP recorded 74 commodity (liquids) spills and leaks totaling approximately 2,921 barrels. This number includes spills and leaks that were reportable to any regulator in any jurisdiction.
It is important to note that, due to a change that Canada's TSB made to its reporting requirements on July 1, 2014, we cannot accurately compare our 2014 reportable spill frequency or reportable spill volume amounts to our reportable spill frequency and reportable spill volume amounts for previous years.
If the TSB had not changed its reporting requirements, LP would have recorded 100 spills and leaks in 2014, with a volume of 2,943 barrels. These amounts compare with 114 reportable spills and leaks totaling 4,298 barrels in 2013.
Over the past 10 years, LP has delivered over 15 billion barrels of crude oil and liquids with a safety record of 99.9994 per cent. 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. Also, 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.
Liquids Pipelines – Volume of Total Reportable Spills Compared with Total Delivery Volume (2005 – 2014)
||Total Number of Spills (On-site / Off-site) 1,2
||Total Spills Volume (barrels) (On-site / Off-site) 1,2
||Total Annual Delivery Volume 2,3 (barrels)
||Percentage of Annual Delivery Volume Safely Delivered (%)
||Percentage of Annual Delivery Volume Safely Delivered (%) excluding On-site 1 Spill Volumes
||74 5(71 / 3)
(2,807 / 114)
||114 (99 / 15)
|4,298 (2,656 / 1,642)
||77 (65 /12)
|10,178 (6,939 / 3,239)
||58 (50 / 8)
|2,284 (637 / 1,646)
||80 (61 / 19)
|34,122 (2,710 / 31,412)
||89 (83 / 6)
|8,353 (6,524 / 1,829)
||80 (72 / 8)
|2,681 (2,587 / 94)
||59 (52 / 7)
|13,756 (902 / 12,854)
||62 (54 / 8)
|5,434 (3,177 / 2,258)
||70 (63 / 7)
|9,825 (9,448 / 377)
||763 (670 / 93)
|93,852 (38,388 / 55,464)
|99.9994 (average over 10 years)
|99.9996 (average over 10 years)
Gas Pipelines & Processing
In 2014, GPP had three reportable liquids spills totaling 2.38 barrels in its pipeline division and no reportable spills in its trucking division. Two of the three spills were categorized as off-site (totaling four ounces) and the remaining spill (totaling 2.38 barrels) was contained on-site. Two of the three spills involved one barrel or less; one of the spills involved two to 10 barrels. There were zero spills involving 25 barrels or more. The largest spill involved the release of 2.38 barrels of diesel corrosion inhibitor fluid from pipe inside a compressor station. The spills did not impact the environment or waterways.
Using the data collection methods currently available to it, GPP also had three reportable gas releases in 2014 that totaled 78.248 million standard cubic feet (MMscf). Of this total, two were categorized as off-site and one was categorized as on-site.
GPP Total Reportable Liquids Spills by Frequency
GasPipelines & Processing Total Reportable Liquids Spills (2010-2014)
GPP Total Reportable Liquids Spills by Volume
Gas Pipelines & Processing Total Reportable Liquids Spills by Volume (2010-2014)
GPP Total Reportable Gas Spills by Frequency
Gas Pipelines & Processing Total Reportable Gas Releases (2012-2014)
GPP Total Reportable Gas Spills by Volume
Gas Pipelines & Processing Total Reportable Gas Releases by Volume (2012-2014)
Using the data collection methods currently available to it, in 2014, GD reported one major incident. The incident involved an overpressure and minor property damage, but no injuries. GD conducted an incident investigation and has implemented improvements to its management systems aimed at preventing a reoccurrence.
Gas Distribution's Reduction of Third-Party Damages – 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 integrity 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 done in a particular area. As such, a key damage prevention measure is to provide the location of related underground infrastructure to excavators before they dig. By providing this information, GD - and, in particular, Enbridge Gas Distribution - has been successful in reducing damages per thousand locate requests.
Gas Distribution Damages per 1,000 third-party locate requests
How Liquids Pipelines' Spill Performance (Frequency and Volume) Compares with the Rest of Industry
Canada – There are few sources of publicly available pipeline incident data in Canada that we can use to compare our liquids pipelines operations with those of the rest of the industry.
The Transportation Safety Board (TSB) in Canada does provide monthly and annual reports on the number of pipeline incidents that occur on federally regulated pipelines, but we were unable to use the data in the reports for comparison purposes:
- The 2014 reports include inconsistencies in the way that the TSB categorizes incidents. These inconsistencies make it impossible for us to fairly compare LP's spill frequency with that of the rest of the industry in Canada.
- The reports identify incidents involving spills but do not provide spill volumes. This lack of data makes it impossible for us to fairly compare Enbridge's spill volume with that of the rest of the industry in Canada.
Since 2013, Canada's National Energy Board has published summaries of pipeline performance measures based on data collected annually from operators of federally regulated pipelines greater than 50 kilometres long. However, the pipeline performance measures do not include spill frequency or volume.
U.S. – The following graph compares LP's spill frequency in the U.S. compared with that of the rest of the industry in the U.S. According to data from the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration, between 2010 and 2013, LP operated approximately 4.1 per cent of the pipelines in the U.S. From 2010 to 2013, LP experienced 0.015 spills per billion barrel miles, compared with an average of 0.036 spills per billion barrel miles for the rest of the U.S. industry, meaning that LP's spill frequency was about 59 per cent better than that of the rest of the U.S. industry.
Number of Significant Incidents per Billion Barrel - Miles
The following graph compares LP's spill volume in the U.S. compared with that of the rest of the industry in the U.S. From 2010 to 2013, including the volume spilled during our 2010 Marshall incident, LP spilled 16.7 barrels per billion barrel miles in the U.S., compared with 22.1 barrels per billion barrel miles for the rest of the industry, meaning that LP's spill volume was about 25 per cent better than that of the rest of the industry.
Significant Incident Releases Volume (bbl) per Billion Barrel-Miles
Significant Spills, Leaks and Releases in 2014
We define a significant spill or leak as any reportable commodity spill or leak that is greater than 100 barrels (15.9 cubic metres). One barrel of oil is equal to approximately 159 litres or 42 U.S. gallons.
Neither GPP nor GD experienced any significant spills, leaks or releases. LP experienced the following significant spills and releases in 2014:
On January 18, 2014, approximately 113 barrels (18 cubic metres) of crude oil leaked from our Rowatt pump station, south of Regina, on Line 67 after a pressure transmitter steel flex hose failed in the station piping. While the majority of the spill was limited to the grounds of the pump station, a limited amount of oil was carried by high winds onto nearby farmland. We immediately shut down Line 67, isolated the Rowatt station and notified regulatory and provincial officials. We also contained the spill area and crews began remediation efforts. The failed flex hose was subsequently removed and replaced and the line resumed operation on January 19. Incident investigation concluded that the support of the pressure transmitter assembly did not sufficiently protect the steel braided hose from excessive stress associated with the high winds in the area. LP submitted an initial clean-up plan to Canada's National Energy Board (NEB), and has substantially completed the remediation.
On February 25, 2014, approximately 975 barrels (155 cubic metres) of crude oil leaked from station piping within a manifold inside our Griffith Terminal. The released oil was fully contained within the facility. We immediately notified regulators and shut down pipelines in and out of the terminal. Our investigation revealed a failed piping connection and we developed a repair plan, which was approved by the regulator. After repairs were completed, we safely restarted all pipelines at the terminal on February 27. Crews recovered most of the released oil and excavated all contaminated soil, which we delivered to an approved waste handling facility. Throughout the event, we carried out air monitoring as a precautionary measure to protect the safety of our workers and the public. There were no impacts to the local community, wildlife or water. We are continuing to investigate the event to determine lessons learned.
Maxbass, North Dakota
On March 21, 2014, oil was discovered inside a containment berm where Tank 4004 had previously been removed at our Maxbass station. The source of the oil was not clearly evident upon discovery. We immediately isolated, locked and tagged out piping in the vicinity of the visible oil and notified the appropriate regulators and agencies. We also immediately began investigation and recovery efforts. We recovered approximately 200 barrels (31.8 cubic metres) of oil and removed contaminated soil from the site. Through recovery efforts, we discovered that the incident was caused by a leak in an underground tank line that had been connected to Tank 4004 prior to its removal.
On April 18, 2014, approximately 113 barrels (18 cubic metres) of crude oil leaked from a tank mixer at our Edmonton Terminal after a seal failed. We immediately notified first responders and our facility technicians acted promptly to stop the leak from the mixer. All free product was contained within the tank containment berm on site. We recovered the spilled product using vacuum trucks and sent it for disposal to an approved waste management facility. We also took the tank out of service and drained it to repair the tank mixer. The tank was returned to service on May 9. We are conducting a root-cause investigation of the incident to determine lessons learned and prevent similar events from occurring in the future.
On December 16, 2014, approximately 1,346 barrels (214 cubic metres) of crude oil leaked from a valve at the Station 4 pump house within our Regina Terminal facility. We immediately notified regulators. We were able to contain all of the product on site, and recover all of the free product. We disposed of the impacted soil and water at an approved waste management facility, and are investigating the cause of the leak. We submitted an initial clean-up plan to the NEB, and are developing a remedial action plan to address any residual impacts.
Learning from Past Incidents
LP is committed to learning from past incidents so that it continually improves its operational performance and prevents similar incidents from occurring in the future.
To that end, it investigates its spills and leaks – as well as its near misses – to determine their root causes and contributing factors, and incorporates its findings, along with the findings of regulators and other agencies, into action plans. LP then stewards these action plans through to completion with clearly defined timelines and roles and responsibilities.
LP also educates workers about past incidents through safety bulletins, articles on intranet articles, and regular discussions at safety and operations meetings. To help enhance its overall safety and reliability, LP shares the lessons it learns within Enbridge, across industry and with regulators and first responders.
System Integrity and Leak Detection Resources
As per the pie charts below, since our major 2010 spill in Marshall, Michigan, LP has significantly increased its spending on system integrity.
Liquids Pipelines (Canada and U.S.) Sytem Integrity Activity
In addition, the number of employees and contractors in our LP integrity department has nearly doubled over the last four years, from 78 positions in 2010 to 146 positions at the end of 2014. 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 240 at the end of 2014. Some of this growth is due to LP's overall growth, but part of it is due to its increased focus on system integrity, leak detection and pipeline control.
In 2014, Enbridge as a company spent more than $1.2 billion on system integrity and leak detection programs across our operations in Canada and the U.S. The following chart shows how that amount is broken down by business segment:
Dollars Spent on System Integrity and Leak Detection (2012-2014)
Improvements to Management Systems
Management systems ensure we have industry-leading standards, controls and procedures to maintain safe, reliable operations. They also enable employees to execute work consistently across our organization.
At the broadest level, the Enbridge Safety Management System Framework describes how we manage safety and operational reliability across the company. For LP, the Enbridge Integrated Management System (IMS) provides a holistic approach to ensuring that our organization acts in accordance with our internal policies and external regulations through alignment of strategy, processes, technology and people, thereby improving efficiency and effectiveness.
In recent years, our business segments have made a number of changes to management systems to support system integrity:
- In 2014, LP expanded its pipeline integrity management system and consolidated activities critical to pipeline integrity, including life cycle pipeline management; process safety; preventive, monitoring and mitigation plans; and risk assessment processes.
- GD updated its distribution management system by adding enhanced controls that provide more detailed information to employees on how to recognize, communicate and mitigate potential safety hazards in the gas distribution system.
- While GPP has always used a third-party consultant when building and maintaining risk assessment software packages for transmission, gathering, liquids and offshore assets, in 2014, it brought the software package and data management in house to enhance the risk analysis program and provide for more accurate and up-to-date data retention.
Pipeline Inspections and Integrity Digs
Each year, we conduct a significant number of pipeline inspections using sophisticated tools that incorporate cutting-edge imaging and sensor technology, and that are capable of scanning for features that could indicate potential problems. The graph below shows the number of these inspections that we conducted in 2012, 2013 and 2014, by business segment.
Wherever our inspections detected something that needed a closer look, we undertook an integrity dig to expose the pipeline, physically inspect it and make any required repairs. In 2014, we completed 2,550 integrity digs across our liquids and natural gas systems (2,485 in LP and 65 in GPP)
Number of Pipeline Inspections (2012-2014)
Pipeline Inspections by Business segment in 2014
LP employed smart in-line inspection tools on 167 runs to inspect more than 12,030 kilometres (7,475 miles) - about 52 per cent of our active system. LP also carried out 2,485 integrity digs.
GPP carried out 19 in-line inspections on 555 kilometres (345 miles) in our U.S. gas and liquids systems, and completed 65 integrity digs. In addition, it carried out four hydrotests on our pipeline systems.
GD conducted 15 in-line and ultrasonic inspections on 36 kilometres (22 miles) of higher pressure pipeline. During the year, the business segment investigated and mitigated 99 features, including metal loss, deformation and crack indications.
Gas Distribution Pilots New Crawler Tool
In-line inspection tools typically enter one end of the pipeline and exit the opposite end. In the past, this has posed a problem for single-entry pipe in our GD business segment and other areas of our systems.
Since 2013, GD has worked with a vendor to develop and pilot a crawler tool, which we call “pig on a string,” to inspect single-entry pipelines. The self-propelled tool provides an added level of accuracy by recording data as it travels into and then back out of the pipe. By introducing the new technology, GD has found a novel solution to the challenge of inspecting natural gas pipe that was previously inaccessible to in-line inspection tools. In 2014, GD used the tool to inspect well laterals at Enbridge Gas Storage facilities in southwestern Ontario. These well laterals (short sections of natural gas pipe) are some of the higher pressure pipeline sections in GD's system that were beyond the capabilities of traditional in-line inspection tools.
Improvements to Operational Reliability
In our drive to continually enhance our operational reliability, we introduced new assessment techniques and pipeline integrity program improvements in 2014.
Applying 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 2014, LP adapted the safety-case method for liquids pipelines – a highly structured approach that uses probabilistic analysis to assess operating hazards and mitigation plans. LP plans to use this technique as an additional tool to assess the reliability levels of its pipeline assets and the effectiveness of its inspection and damage prevention programs.
Asessing Geohazards along our Liquids Pipelines System
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). These have the potential to move the pipeline, resulting in stresses or strains that could cause the pipeline to fail.
Since 2012, we have developed a comprehensive geohazard process management program for our liquids pipelines. Over the last three years, this program has involved extensive assessments, with geotechnical engineers and other specialists identifying and inspecting more than 5,000 geohazard sites, primarily river crossings and slopes. In some cases, as follow-up action, we have replaced pipe, remediated high-risk slopes and installed strain gauges to monitor the condition of the pipe. Based on risk levels, we have selected a number of sites for annual inspections. In 2014, we inspected more than 2,800 geohazard sites in Canada and the U.S., including slopes and water crossings.
Increasing our Focus on Facility Integrity
As we increase system integrity programs for our Mainline system, we are also focusing attention on the integrity of our facilities.
In 2014, we continued to proactively identify and address potential threats in our LP facilities before a release occurs. We completed a two-year study to identify and characterize the likelihood of failure on more than 5,000 small-diameter piping connections in our LP facilities. We will use the findings to plan future maintenance and repair programs.
LP is also applying new technologies to screen for defects on facility pipelines that are unpiggable or difficult to inspect due to the pipe and valve configuration. 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 2014, LP successfully used the technology to inspect 15 kilometres (nine miles) of facility piping, including tank lines, at terminals in Cushing, Oklahoma and Superior, Wisconsin.
LP has also applied a radiographic tool to inspect small-diameter drain-line connections at facilities across its system. The technology provides a detailed image of piping, similar to an x-ray, to detect wall loss due to internal corrosion. LP is using the tests to identify areas of internal corrosion, often caused by sediment build-up, so as to take early action to repair or clean the drain lines.
Under Occupational Safety and Health Administration (OSHA) regulations, operators in the U.S. are required to inspect gas processing plants every five to 10 years. GPP follows a rigorous schedule to assess the mechanical integrity of its 28 natural gas processing plants, inspecting 20 per cent of every plant each year and checking vessels and piping for corrosion. The results of these inspections are logged into a database to track corrosion trends and operational reliability.
Improvements to Process Safety Management
Another way that we are enhancing system integrity and increasing the safety of our pipelines is through process safety management. Process safety is a disciplined management approach applied in hazardous industries that focuses on the prevention, detection, control and mitigation of catastrophic incidents that have the potential to injure people and claim lives, or have far-reaching and long-lasting consequences.
Process safety management involves a comprehensive set of industry 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 consistent development of process safety programs across our organization through a Joint Business segment Process Safety Council, which reports to Enbridge's Operations and Integrity Committee. Through the council, senior leaders from each business segment 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 are being addressed are:
- Incident investigation procedures
- Process safety information (equipment information and standards)
- Management of change (controlling changes to prevent unplanned impacts to operational reliability)
- Assessment and mitigation of process safety hazards
We are also working to better understand process safety risks at our critical facilities. In 2014, an LP team completed a comprehensive review of process safety risks at our Superior Terminal in Superior, Wisconsin. Using a highly structured analysis, the team evaluated past operating events, current practices and potential risks at the terminal. While the review identified some opportunities for improvement, it also confirmed that high levels of operational reliability are in place.
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.
Since 2012, LP has invested $190 million to review the performance of critical leak detection equipment across its system and add equipment, as needed. As a result, LP has significantly increased the number of remote pressure, flow, temperature and density transmitters in place across Enbridge's liquids pipelines system. This capital program was substantially completed in 2014.
In addition, LP initiated a rupture-detection program to complement its existing leak detection strategy. LP has made significant strides in developing this additional protective layer and will be deploying phase one of the program in early 2015.
In 2014, LP also executed computer-simulated tests to measure and understand leak detection performance across its entire pipeline system. These tests were further complemented with four additional unannounced fluid withdrawal tests. Fluid withdrawal tests allow LP to evaluate both the performance of its system and its people to identify further improvements to processes and technology.
GD has enhanced its knowledge of the characteristics of its natural gas distribution system through targeted risk assessments of assets. In 2014, GD conducted leak surveys on 8,035 kilometres (4,993 miles) of distribution mains in the Enbridge Gas Distribution (EGD) franchise area – which equals approximately a quarter of EGD's system.
Enbridge Gas Distribution has also partnered with 3-GIS LLC to develop a new Leak Survey Management System, a GIS-driven, GPS tracking tool to manage its leak survey programs. Implemented in August 2014, the system has brought greater confidence about the condition of the assets in Enbridge Gas Distribution's natural gas system by improving governance and execution of the leak survey program. The 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.
Research and Development of Innovative Technology
We are committed to continuous improvements to ensure the safety and reliability of our pipelines. We invest in innovative pipeline integrity, leak detection and damage prevention technologies, with the goal of implementing industry-leading capabilities. For more information on these, please see the R&D and Innovation: Pipeline Technologies and Emerging Technologies section of this website.
We help to shape industry direction through our leadership roles and are working hard to promote and secure a future where zero incidents are attainable. We actively support the development of best practices and advanced technology by taking lead roles on Pipeline Research Council International (PRCI). We also work alongside industry peers through associations such as the Canadian Energy Pipeline Association (CEPA), the Canadian Gas Association (CGA), the American Petroleum Institute (API) and the American Gas Association (AGA).
Here are some examples of our collaborative work with industry associations in 2014:
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 technologies for liquids pipelines. Completed in 2014, this data review initiative has collected the industry's most comprehensive body of knowledge related to crack management. We sponsored this project and have been providing leadership from inception to completion.
Over the past two years, we have participated in an API-led industry initiative to develop a white paper on rupture detection for the pipeline industry. The strategy document will assist pipeline operators in North America in establishing best practices related to rupture detection as a primary or complementary layer to existing leak detection systems.
Joint Industry Partnerships
We have helped 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.
Over the past two years, we have participated in an API-led industry initiative to create a safety management system for the pipeline industry. This recommended practice is expected to be released in 2015. In addition, through a subcommittee of the AGA Safety and Occupational Health Committee, we are sharing the development of industry practices for process safety in the natural gas distribution industry.
At Enbridge, we promote the sharing of best practices with our industry peers and encourage our people to get involved. In 2014, our employees presented many technical papers on different topics related to system integrity and leak detection at industry conferences and speaking engagements. Through these activities, we are not only driving industry improvements but advancing a culture of innovation in our organization.