Science, Irving K. Barber Faculty of (Okanagan)
Earth, Environmental and Geographic Sciences, Department of (Okanagan)
DSpace
UBCO
Reimer, Karaline
Master of Science - MSc
University of British Columbia
The natural gas pipeline industry in British Columbia can appear to be a complicated patchwork of agencies and organizations working in jurisdictional silos that prevent the easy transfer of information. Even life-cycle agencies can appear to work within their mandated zones of control, with little impact on the broader evolution of the industry. This thesis helps determine and define what the regulatory and interagency framework of the natural gas pipeline industry in BC looks like, how the agencies and industry groups communicate on both formal and informal levels, and how they learn and share information to further the safety of the industry as a whole. To identify the roles that pipeline organizations and agencies play in the industry, a detailed examination was conducted of the key agencies involved in the pipeline regulatory life-cycle, describing their history, mandates, roles and responsibilities in the province. Communication between these groups was examined through focus groups with the two dominant regulators (BC Oil and Gas Commission and the Canadian Energy Regulator) in the province. The evolving tolerances for risk and how learning from lessons has been applied over time was studied through a timeline of incidents and policy changes in the province, and in five case studies that showcased some causes of pipeline failure and the evolving nature of incident investigation. The results of this study suggest that the regulatory landscape for the natural gas pipeline in British Columbia is evolving towards one with a lower tolerance for risk, higher safety standards, and a better understanding of how to mitigate issues. Regulators and industry organizations maintain extensive communication, both formal and informal, through various channels and mechanisms, which enhance their effectiveness (the ability to meet mandates and achieve system efficiency and public safety) and cooperation (the sharing of information, coordination of activities to maximize effectiveness). The agencies are learning organizations in that they work to promote information sharing, transparency, and adaptation of policy based on the lessons learned, particularly from incidents
A LONGITUDINAL STUDY OF THE NATURAL GAS PIPELINE INDUSTRY IN BRITISH COLUMBIA by Karaline Reimer B.Sc., The University of Victoria, 2012 A THESIS SUBMITTED IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE in THE COLLEGE OF GRADUATE STUDIES (Earth and Environmental Sciences) THE UNIVERSITY OF BRITISH COLUMBIA (Okanagan) September 2022 © Karaline Reimer, 2022 ii The following individuals certify that they have read, and recommend to the College of Graduate Studies for acceptance, the thesis entitled: A longitudinal study of the natural gas pipeline industry in British Columbia submitted by Karaline Reimer in partial fulfillment of the requirements of the degree of Master of Science. Dr. Kevin Hanna, Irving K.Barber Faculty of Science, Dept. of Earth, Environmental and Geographic Sciences, UBC Okanagan Supervisor Dr. Edouard Asselin, Faculty of Applied Science, Dept. of Materials Engineering UBC Vancouver Supervisory Committee Member Dr. Kasun Hewage, Faculty of Applied Science, School of Engineering, UBC Okanagan Supervisory Committee Member Dr. Alon Eisenstein, Faculty of Applied Science, School of Engineering, UBC Okanagan University Examiner iii Abstract The natural gas pipeline industry in British Columbia can appear to be a complicated patchwork of agencies and organizations working in jurisdictional silos that prevent the easy transfer of information. Even life-cycle agencies can appear to work within their mandated zones of control, with little impact on the broader evolution of the industry. This thesis helps determine and define what the regulatory and interagency framework of the natural gas pipeline industry in BC looks like, how the agencies and industry groups communicate on both formal and informal levels, and how they learn and share information to further the safety of the industry as a whole. To identify the roles that pipeline organizations and agencies play in the industry, a detailed examination was conducted of the key agencies involved in the pipeline regulatory life-cycle, describing their history, mandates, roles and responsibilities in the province. Communication between these groups was examined through focus groups with the two dominant regulators (BC Oil and Gas Commission and the Canadian Energy Regulator) in the province. The evolving tolerances for risk and how learning from lessons has been applied over time was studied through a timeline of incidents and policy changes in the province, and in five case studies that showcased some causes of pipeline failure and the evolving nature of incident investigation. The results of this study suggest that the regulatory landscape for the natural gas pipeline in British Columbia is evolving towards one with a lower tolerance for risk, higher safety standards, and a better understanding of how to mitigate issues. Regulators and industry organizations maintain extensive communication, both formal and informal, through various channels and mechanisms, which enhance their effectiveness (the ability to meet mandates and achieve system efficiency and public safety) and cooperation (the sharing of information, iv coordination of activities to maximize effectiveness). The agencies are learning organizations in that they work to promote information sharing, transparency, and adaptation of policy based on the lessons learned, particularly from incidents. v Lay Summary This thesis is broken into four chapters that aim to clarify and contextualize the existing natural gas pipeline regulatory infrastructure for the province of British Columbia, describe the interface between regulatory bodies and industry members, and discern to what extent the industry has evolved over time. Chapter 1 introduces the thesis, lays out the research questions that bound the thesis and introduces the natural gas pipeline in British Columbia. Chapter 2 explores the roles different regulators and industry members play in pipeline processes from application to failure and examines the communication that occurs between agencies using focus group discussions with regulators. Chapter 3 examines the theory behind operational learning and challenges to evolution in an industrial environment. Chapter 4 is a longitudinal survey of pipeline incidents that explores the organizational learning of the pipeline industry and government regulators over time through five case studies and a timeline of pipeline incidents in the province. Chapter 5 concludes the thesis while reiterating answers found to the research questions of Chapter 1 and provides recommendations to government. Research findings suggest that overall, the pipeline industry in BC is improving in safety, transparency, and communicating lessons over time. There are still challenges to the industries evolution including a lack of data standardization across different jurisdictions and a lack of access to quality reporting. This research is a qualitative analysis that also relies on documentation, focus groups with key life cycle regulators. vi Preface The development of the research and the analysis was completed independently, with guidance from my supervisors Dr. Kevin Hanna and Dr. Edouard Asselin as well as committee members Dr. Mathieu Bourbonnais, and Dr. Kasun Hewage. Two manuscripts are included as chapters in this thesis with the abstracts removed and will be submitted for publication in peer reviewed academic journals. Because of the manuscript format, the methodology is repeated in part in some sections of the thesis. This research project design including the list of focus group did not require and ethic review because the scope of the interview questions and focus of the research, which was on regulator policy itself, not the individuals participating in the interviews. Individuals were not the subject of the research, the agencies and organizations were and they provided an organizational perspective. vii Table of Contents Abstract ......................................................................................................................................... iii Lay Summary .................................................................................................................................v Preface ........................................................................................................................................... vi Table of Contents ........................................................................................................................ vii List of Figures .............................................................................................................................. xii List of Abbreviations ................................................................................................................. xiii Acknowledgements .................................................................................................................... xiv Chapter 1: Introduction and Setting ............................................................................................1 1.1 The Problem and the Research Questions ...................................................................... 3 1.2 Organization of the thesis ............................................................................................... 5 1.3 Method ............................................................................................................................ 5 1.3.1 Document analyses and chronology ........................................................................... 6 1.3.2 Case Studies ................................................................................................................ 7 1.3.3 Focus Groups .............................................................................................................. 8 1.4 Limitations of the research ............................................................................................ 10 Chapter 2: Roles and Regulations within the pipeline industry ..............................................11 2.1 Methodology ................................................................................................................. 13 2.2 Industry and other private sector organizations ............................................................ 14 2.2.1 CSA Group (Canadian Standards Association) ........................................................ 14 2.2.2 The Canada Energy Pipeline Association ................................................................. 16 2.3 Pipeline Government Regulators .................................................................................. 17 viii 2.3.1 The British Columbia Oil and Gas Commission ...................................................... 17 2.3.1.1 What does the BC Oil and Gas Commission Regulate? ................................... 19 2.3.1.2 BC Oil and Gas Act .......................................................................................... 22 2.3.1.3 BCOGC Assessment and Consultation ............................................................. 23 2.3.1.4 BCOGC Emergency Response Role ................................................................. 25 2.3.2 BC Utilities Commission .......................................................................................... 26 2.3.3 WorkSafeBC ............................................................................................................. 27 2.3.4 Environmental Assessment Agencies ....................................................................... 27 2.3.5 CER (Canadian Energy Regulator, formerly National Energy Board (NEB)) ......... 32 2.4 Responders .................................................................................................................... 41 2.4.1 B.C. Ministry of Environment & Climate Change Environmental Emergencies Department ............................................................................................................................ 41 2.4.2 Transportation Safety Board (TSB) .......................................................................... 42 2.5 Analysis......................................................................................................................... 48 2.5.1 Conclusion ................................................................................................................ 52 Chapter 3: The evolving nature of pipelines, risk management and incident response in British Columbia ..........................................................................................................................55 3.1 Introduction ................................................................................................................... 55 3.2 Methodology ................................................................................................................. 56 3.3 Literature Review.......................................................................................................... 56 3.3.1 Industrial learning from incidents ............................................................................. 56 3.3.2 Institutional perception of risk and how it affects incident learning ........................ 64 3.3.3 Risk analysis ............................................................................................................. 65 ix 3.3.4 Accident investigation and reporting ........................................................................ 69 3.3.5 Risk Communication ................................................................................................ 70 3.3.6 Conclusion and challenges to risk management for the pipeline industry ................ 72 Chapter 4: A Chronology of Pipeline Events in BC .................................................................73 4.1 Introduction ................................................................................................................... 73 4.2 Methodology ................................................................................................................. 73 4.3 Pipeline event timeline .................................................................................................. 74 4.4 Pipeline incident case studies........................................................................................ 80 4.4.1 Case Studies Involving Geohazards: Monias & Zymoetz pipelines ......................... 81 4.4.2 Monias Pipeline Rupture 1997.................................................................................. 89 4.4.3 Zymoetz Creek Incident ............................................................................................ 93 4.4.4 Encana Sour Gas Pipeline Failure (Swan Wellsite) 2009 ......................................... 99 4.4.5 Nig Creek Pipeline (Westcoast Energy Inc.) and Bonavista Energy Corporation (Bonavista) Pipeline ............................................................................................................ 105 4.4.6 Case Study of Stress Corrosion Cracking - Westcoast Energy Prince George Incident ............................................................................................................................... 115 4.4.7 Conclusion .............................................................................................................. 132 Chapter 5: Conclusions and Recommendations .....................................................................139 5.1 Challenges and Future Study ...................................................................................... 139 5.2 Conclusion .................................................................................................................. 140 5.3 Recommendations ....................................................................................................... 143 Bibliography ...............................................................................................................................145 Appendices ..................................................................................................................................171 x Appendix A Questions asked of regulators during the focus ................................................. 171 xi List of Tables Table 1.0. Provincial acts and regulations that are wholly or partially under the pureyaance of the BCOBC (2020). ...................................................................................................................... 19 xii List of Figures Figure 2.1. Flowchart of regulation during the application, construction, and operational phase of a pipeline project in British Columbia ...................................................................................... 39 Figure 2.2. Spill response flowchart for provincially regulated natural gas pipelines in BC. ..... 47 Figure 2.3. Spill response flowchart for federally regulated natural gas pipelines in BC. .......... 47 Figure 4.1. Location map of the Monias pipeline incident .......................................................... 89 Figure 4.2. Location of the Zymoetz Creek pipeline incident. .................................................... 93 Figure 4.3. Location map of the sour gas pipeline incident ......................................................... 99 Figure 4.4. Location map of Nig Creek pipeline incident. ........................................................ 109 Figure 4.5. Location map of Prince George pipeline incident. .................................................. 124 xiii List of Abbreviations BCEAO – British Columbia Environmental Assessment Office BCOGC – British Columbia Oil & Gas Commission BCUC – British Columbia Utilities Commission CEPA – Canadian Energy Pipeline Association CER – Canada Energy Regulator CSA – Canadian Standards Association DRIPPA – Declaration on the Rights of the Indigenous Peoples Act EA – Environmental Assessment EEP – Environmental Management Act EIA – Environmental Impact Assessment IAAC – Impact Assessment Agency of Canada NEB – National Energy Board TSB – Transportation Safety Board of Canada UN – United Nations US EIA – United States Energy Information Administration xiv Acknowledgements I offer my enduring gratitude to the faculty, staff and my fellow students at UBC, who have inspired me to succeed in challenging times. I owe particular thanks to Dr. Kevin Hanna, for his guidance and insights that made this work possible. I also want to thank Dr. Edouard Asselin and the Pipeline Integrity Institute at UBC for their support. A special thanks are owed to my parents, who have supported me unfailingly in all my endeavors and have always encouraged my curiosity. I would also like to thank my partner Chris for all of his moral support that helped me through the research and writing. 1 Chapter 1: Introduction and Setting British Columbia has long been a producer and exporter of natural resources, in line with Canada’s economy as a whole. While most people might link BC natural resource exports to the well-known forestry industry, the province is also the second largest producer of marketable natural gas in Canada (BCOGC, 2017). Natural gas was first discovered in BC in 1889 by a railway company that was prospecting for coal (CERI, 2016). Little development of the resource was pursued until the Second World War, where an interest in the development of Canada’s oil and gas sector was revitalized in a bid to pursue energy independence. The first successful gas well was drilled in 1947 (Janicki, 2008). With the development of BC’s natural gas fields, came the building of supporting infrastructure, and especially pipelines. From the 1950s through to the 1980s there was gradual development of the natural gas industry, predominantly in the northeast of the province, and the construction of pipelines that transported product south and west to the consumer market. Advances in drilling technologies in the 1990s revitalized gas development in BC, using horizontal drilling, and more recently hydraulic fracturing methods, to increase production and the viability of BC’s considerable tight, or shale gas, resources. The abundance of sources of shale and tight gas are changing the dynamics of Canadian energy supplies. BC’s sources now account for 35% of Canada’s natural gas resources, 90% of which can be found in the Montney Shale and the Horn River Basin (CERI, 2018), located in the Northeastern part of the province. Despite increasing competition and demand for alternative energy sources there is no slowing of natural gas development in the province at this time. Recent forecasts from the Canadian Energy Research Institute (CERI) for Canada’s natural gas industry, which assess current conditions and expectations for the next 20 years, have found that the most economically viable natural gas 2 wells, both vertical and horizontal, are in the province of BC (CERI, 2016). As a consequence of the growth of natural gas production in the province, there is increasing demand on the existing pipeline infrastructure, as well as a push for building new lines. The province has made it clear that the continued development of the natural gas industry in BC is a priority. In 2012, the province issued a Natural Gas Strategy which recognized natural gas as a designated provincial priority and listed a series of actions the province would undertake to promote the industry (CERI, 2016). In 2013, then BC Premier Christie Clark, campaigned in an election on the promise of developing a provincial Prosperity Fund through natural gas exports to foreign markets, specifically targeting Asian markets (CBC, 2016). While this has yet to materialize, the belief in a strong natural gas sector being key, or a part of, provincial prosperity has been embraced by successive BC governments. In 2018, BC Premier John Horgan announced a “new approach” that would welcome investment that promoted the interests of the people of BC first when describing the progressing natural gas pipeline linking natural gas plays in the northeast of the province to a terminal in Kitimat. While speaking to the challenges surrounding BC’s climate goals, the premier alluded to the economic draw of the project, stating “No premier or government can dismiss this kind of critical economic opportunity for the people of British Columbia” (BC Gov News, 2018). From both an engineering, or technical perspective, and a policy view one of the most challenging steps in the progression of these economic goals has been the construction of the pipelines that connect places of extraction to places of consumption. The focus of this research is on natural gas pipelines and the regulatory setting in British Columbia. This focus helps bound the research geographically and avoid the challenges that are unique to policy and conflict discourses over the respective products, allows study of the 3 most extensive type of product pipeline in BC, and provide a well-defined way of examining the learning functions of agencies with respect to a specific type of line and product 1.1 The Problem and the Research Questions As of 2019, there was about 38,546 km of operating pipelines in the province of BC (BCOGC, 2019), approximately 80% of which carry natural gas. This is the dominant line use in BC. Increasingly pipelines have become a contentious issue in Canada, and particularly in British Columbia. While public discourse and controversy is primarily focused on the transportation of oil, natural gas pipeline development has also become a debated topic, albeit mostly with respect to regional projects, such as a line in norther BC being built through a portion of the territory of the Wet'suwet'en people. This can suggest that controversies over pipeline construction and operation may have more to do with the product they carry than the line itself. Natural gas lines for example, are arguably more relatable to consumers and seem ‘useful’ to the public at large than an oil trunk line, due to the familiar use of gas in homes for heating and cooking. Regardless of the product, there is growing concern, awareness, and perception challenges associated with pipeline construction and operation. While research has shown that pipelines are the safest way to transport products (Barrios de Cunha, 2016; Bonvincini et al., 2015; Dziubínski et al., 2006, Carvalho et al., 2008, Brito and Almeida, 2009; Brito et al., 2010; Furchtgott-Roth, 2013), failures do occur and seem to generate a greater amount of public discourse than other equivalent industrial incidents. A key challenge (the problem) is that there can be a perception that pipeline companies are not held to sufficient liability over incidents and spills when within BC, though unlimited liability exists in the case of a pipeline incident (NRCAN, 2019). Policy aspects, such as liability, can feed an impression of 4 unaccountability, lack of learning or sufficient responsiveness to incidents and accidents, and static or unresponsive lifecycle regulators. It can seem unclear ‘who does what’, ‘who is responsible for what’, and how the different policy and regulatory actors work together -- or if they do. While descriptions of responsibilities are provided by individual agencies, mapping out their respective roles, in one place, is rarely if ever done. This is a descriptive exercise, but it can be important for understanding the setting, and it requires some skill to both describe and interpret their roles. A major objective of this research is to examine this perception problem, by looking at how agencies and industry learn from incidents on natural gas pipelines, the policy or other responses they provide, and how they interact and coordinate their work. The research addresses 4 questions: 1. What are respective roles and responsibilities of the agencies that regulate the pipeline industry in BC? This is a descriptive and interpretive contribution. 2. What changes are made by agencies, and industry, after an incident. Put another way, what lessons are taken and applied after an event? This is case study-based contribution. 3. How do lifecycle regulators at two different levels of government (federal and provincial) interact, coordinate, share knowledge, and work together at an inter and intra jurisdictional level. This is based on focus group interviews and provides insight into inter and intra level interaction, integrative action, and collaboration. 4. Do the lifecycle regulators exhibit the qualities of a learning organization? This is based on the focus groups, the case studies, and to a lesser extent the literature review. This provides a more holistic understanding of the regulatory setting for lifecycle regulation of the industry. 5 1.2 Organization of the thesis The thesis is organized around a manuscript model. Chapter 1 provides the overall context and the method. Chapters 2 and 4 respectively cover the organizational aspects of the regulatory setting, and a chronological review of incident and outcomes, including five detailed case studies. Chapter 2 provides a descriptive summary of the roles and responsibilities of the regulatory and industry agencies that are involved in natural gas pipelines in BC. The chapter explores the communication between agencies and how they interact over the lifecycle of a pipeline. Chapter 3 examines the evolving nature of risk and how it has shaped changes in the industry. Chapter 4 examines organizational learning in the industry and the evolving nature of risk. These subjects are explored through a longitudinal survey of evolutions in the industry and a deep dive into five separate incidents. A literature review is woven throughout Chapters 2, 3 and 4 to provide context to the issues discussed. Chapter 5 provides conclusions which are organized around the research questions noted above. 1.3 Method The overall approach, or method, to the thesis research is qualitative, but this requires several tools to provide data and analyze it. This is not a mixed methods approach per se, which would involve a combination of qualitative and quantitative methods/tools. But the approach developed and used here embodies some of the theory characteristics of mixed methods. Specifically, the approach has three characteristics which guide the research (Greene and Hall, 2010; Greene, 2007 and 2015; and Greene et al, 1989). 6 1. Triangulation. The research seeks convergence, corroboration, correspondence of results using different qualitative methods. In this research this actually includes four components: a descriptive and analytical outline of agencies and their responsibilities, incident case studies, a chronology of incidents, and the policy or learning outcomes, and focus groups with lifecycle regulators (see also Erzberger and Prein 1997). 2. Complementarity. The research uses the different tools to seek elaboration, enhancement, illustration and/or clarification of the results from one method with the results or outcomes from the other. 3. Expansion. The research extends the range of study by using different methods for the different research questions. There are exploratory and convergent qualities to the method developed for this research (see Creswell and Plano Clark, 2010). The exploratory quality involved developing the description of the agencies roles/responsibilities and the chronology of events. The latter informed the selection of case studies, and these together informed the focus group questions. The convergence quality is in the bringing together of the outcomes and information generated by the different tools. The method used in the thesis provides a novel interpretation and adaptation of the literature on mixed methods approaches, while providing multiple nodes or sources of data and information based on a qualitative research design. 1.3.1 Document analyses and chronology The descriptions of the agency responsibilities were derived from a combination of industry and government regulator documentation and provincial or federal acts. For provincial 7 and federal regulators, their jurisdictions and responsibilities are determined through the courts systems and laid out in Acts, such as the Oil and Gas Act that governs the actions of the BC Oil and Gas Commission. These acts describe the essential services that regulators must provide and are to be held accountable to. Regulators also regularly publish documents that provide further details and information regarding their work, which was used to inform Chapter 2 of this thesis. For non-government regulators, information related to their roles within the industry was largely gathered directly from their websites and published documents. These documents included multi-agency, cross industry publications that were the work of industry collaborations with academic research such as the Stress Corrosion Cracking Manuals. 1.3.2 Case Studies Yin (2009) describes case studies as a valuable tool for explaining facts and experiences. The case studies developed here show how regulators, and industry, responded to an incident and used the experience to modify policy and/or practice. The case studies were created using a review of publicly available published documents as well as literature review. This includes incident reports published by the Transportation Safety Board and the BC Oil and Gas Commission. The case studies are: the Monias Pipeline incident (1997), the Zymoetz Creek Incident (2002), the Encana sour gas pipeline failure (Swan Well Site, 2009), the Nig Creek/Bonavista Pipeline Incident (2012), and the Westcoast Energy Prince George Incident (2018). Four factors guided the selection of the case studies: the size and scale of the incident, the impact on the public, the availability of documentation, and using incidents caused by the statistically most likely causes of pipeline failure in British Columbia. The case studies are outlined in Chapter 3. 8 The case study approach is an explanatory case study model, which includes an accurate description of the facts or events of the incident, and then its outcomes and conclusions based on a sound explanation that reflects the observed reality (see Mills, Durepos, and Wiebe, 2011). The outline of each case study follows a similar structure -- a case study logic model. Logic models are narrative depictions of reality processes that are built following a problem (situation) in each context (Kalu & Norman, 2018). The logic model provides links between the situation (problem) and processes employed in solving the problem. The chronological approach was used because the events and outcomes of the are cases defined by time (Yin, 2009). Yin (2009) defines the principles of qualitative case studies as a set of analytical questions. These questions are modified in this thesis to cover: 1. who was involved; 2. where the incident occurred; 3. why, what and how it happened, and 4. the outcomes (regulatory, policy or other). 1.3.3 Focus Groups Two focus groups were conducted, one with Canadian Energy Regulator (CER) staff, and one with BC Oil and Gas Commission (BCOGC) staff. A focus group provides a directed conversation with a group of individuals who are all connected to the discussion topic (Cyr, 2016; Curry, Nembhard, & Bradley, 2009). In this research the focus groups provided an organizational perspective and experiences, and not accounts of individual experience or opinions. In this vein, the approach I employed helped reveal group consensus (Cyr, 2016), which helps provide a collective insight into the work of organization (see Thiessen et al, 2020 and Peletz et al,). The approach was also important for obtaining assistance from the CER and the BCOGC because participants could collectively respond to, and discuss, the issues and not feel that either they were the subjects of the research, or that their answers might not represent the broader experience of the organization. Focus groups are fundamentally ‘social events’ that provide data 9 through interaction (Smithson, 2000). The participants were at a senior administrative, policy, and operational level within their respective organizations. Collectively they contributed a comprehensive understanding of their organizations work and perspective. The approach provided a place for discussion for discussion within a context where issues and the work of the organizations are not uncommonly subject to public critique. It also allowed for collective reflection, sharing of information unique to sections within the organization, and the collective construction of a narrative that ultimately represents the organization’s experience and ‘opinion’. In my research, the focus groups helped validate the data or information collected in the document review and the case studies, afforded a unique opportunity to learn about integrative mechanisms (e.g. for inter and intra organizational collaboration, resource sharing, information sharing, and action) that would not necessarily be apparent from agency websites, reports, or the case study documents. It also allowed participants to reflect on the challenges in these areas and improvements they have seen in integrative qualities. Focus groups as a research tool can experience challenges with respect to validity and reliability (Kidd and Parshall, 2000:294), which makes their use in this research to add context and value to document analyzes and case studied, an important element, but not the only one used. For each focus group, it was noted to participants that the purpose is not to share their individual opinions, and that they were not the subjects of the research, but instead it was a setting to collectively share the organization’s experiences and perspectives. There were six participants in the CER group and eight in the BCOGC group. The participants are in senior positions within their organization and brought specific knowledge and experience in policy, operations, standards development, and incident responsiveness. The participants were invited by email. In both instances, the agency also facilitated contacts and helped set up the focus group meeting. 10 Participation was voluntary and there was no workplace requirement to take part in the focus group. Notes were transcribed throughout the focus groups, there was no audio or visual recording taken. Each focus group was about 2.5 hours. Questions were also provided in advance of the meeting. Two researchers managed each focus group, the author of this work and the thesis advisor for the project. One posed the questions and helped keep the conversation on track (for timing and subject area), while the other took notes. 1.4 Limitations of the research This thesis is not an exhaustive depiction of all aspects of the natural gas pipeline in the province. For the sake of brevity in a Masters thesis, several components such as marine oil or gas transportation, terminals, oil pipelines or engineering or technical discussions about pipeline failure were excluded from the research. Focus was kept to life-cycle regulators because of their involvement in all aspects of pipeline operations including incident response and investigations. The focus groups chosen from the regulators were kept to an agency perspective only, eschewing personal opinions and as such may not necessarily identify individual opinions that are at odds with the organization’s views, which would be very difficult to obtain. There was consideration given to the incorporation of more geospatial research components to explore incident statistics across the province. After the exploration of available data sets and the processing options available, it was ultimately decided that, while a valuable avenue for future research, it was beyond the scope of this thesis. 11 Chapter 2: Roles and Regulations within the pipeline industry The provincial regulatory agency for pipelines operating in BC, the BC Oil and Gas Commission (BCOGC), reported 10 incidents1 with a release for 2019, which is a frequency of 0.17 per 1000 km2 of the pipeline (BCOGC, 2019). The federal rate of incidents on pipelines across Canada for 2019 was 0.7 per 1000 km of pipeline, falling well below the average of 1.8 seen in the period 2011 to 2018 (TSB, 2019). Federal reporting does include incidents that occur in BC that are under federal jurisdiction, a distinction that will be explored further in this thesis. Pipeline incidents in BC are primarily caused by three primary failure mechanisms: geotechnical failure, third-party damage, or corrosion. Other methods of failure such as operating beyond pipeline limits is increasingly rare in modern times (TSB, 2019). Nearly all incidents demonstrate a combination of engineering and human error that allows pipeline companies and the regulatory infrastructure governing pipeline operation in British Columbia to learn from incidents and incorporate lessons into future operations and construction requirements. The ability of the pipeline industry and regulators to adopt policy tools (e.g., USA Congress, 1995) and promote learning organizations (e.g., Garvin, 2003) that incorporate lessons learned from incidents into future policy is assessed in this thesis. Through an evaluation of the incidents and regulatory policy over the past 40 years, using literature scans, case studies, and focus groups to analyze both current and historical there is an opportunity for this work to discern if the natural 1 An incident is defined as an occurrence, condition or situation arising in the course of operations that resulted in or could have resulted in service interruption or damage to equipment or personell. 2 Pipeline incidents are reported as a number per 1000 km to create a mathematical average over a linear distance 12 gas pipeline industry in British Columbia is engaging in its commitments to promote safe practices, or if it aligns with what might be the public perception of its risks. Communicating a better understanding of the regulatory structures of the pipeline industry and how groups interact and communicate may go some way to alleviating some negative perceptions surrounding the industry as a whole. The regulatory landscape for British Columbia’s natural gas industry may seem opaque to those outside the industry, and indeed some individuals inside confess that it can seem confusing at times. The boundaries between federal and provincial jurisdictions are neither overlapping nor integrated; however, they do run parallel to each other. Adding to the complexity of the sector is the reality that jurisdictional responsibility is not only divided by pipeline size, geography, and scale of operation. There are private sector industry representatives that inform public regulators, and organizations that represent the industry, or specific parts of industry operations. Within the government realm, some entities regulate pipeline construction and planning, others oversee the day-to-day operations of pipelines, and a third sector becomes involved only in the event of an incident. Some of these regulators have a role to play in more than one of these tasks. In this chapter, I summarize the organizations involved in British Columbia’s natural gas pipeline industry and outline the roles they play if an incident becomes a pipeline spill response. I compare and contrast them by illuminating their involvement in different aspects of the pipeline regime in BC and revealing the lines of communication that inform decisions on permitting and response in the industry and government. Using the information gathered during focus groups with federal and provincial regulators, I explore how the agencies interact, coordinate, share knowledge, and work together at an inter and intra jurisdictional level. 13 2.1 Methodology The methodology of Chapter 2 is primarily descriptive, or qualitative, utilizing publicly available information and legislative acts to describe what roles agencies and industry groups fulfill in the natural gas pipeline framework of the province. Bringing the roles of each agency together and examining their connections or perceived lack therein is a novel way to look at an industry that it typically perceived through the lenses of individual issues. Additional insight into the interconnectivity of agencies and their communications is provided through focus groups that were held with regulators for the purpose of this thesis. The chapter is organized around the types of organizations that make up the natural gas pipeline regime in British Columbia and clarifying what role they play in the industry. The control and oversight exerted by regulators and private sector organizations at different phases in the lifecycle of a pipeline, including after an incident is explored, analyzing the effectiveness of various agencies. Research for this chapter of the thesis was based on the review of existing literature, as well as the available technical or regulatory documentation published by industrial or government agencies. Some of this documentation was proprietary to the individual agencies, and some was the result of inter-agency technical groups. The primary methodology used to explore how agencies and industry members work together was through two separate focus groups that were set up with the primary life-cycle regulators in the province—the BC Oil and Gas Commission and the Canada Energy Regulator. The two agencies are responsible for the provincial and federal natural gas pipelines that cross the province and have the broadest perspective on the industry from conception of a project to the aftermath of an incident. Participants in the focus groups were senior members of their agencies an most had many years of experience within the organization and industry. Questions 14 were prepared and shared with participants in advance, and it was stressed that the objective of the focus group was to understand of know the perspective of the agency, rather than any personal opinions which would represent a challenge. The responses were not recorded through visual or audio means, however notes were taken. The focus group methodology creates an environment that encourages a far less homogenous texture of discourse than can be found in individual interviews, rather participants can relate their experiences and reactions among peers with whom they share a common reaction (Kidd & Marshall, 2000). Focus groups may also elicit a broader range of responses to questions and elicit details that would have otherwise been overlooked, giving the research a more robust perspective. Additionally, given the somewhat sensitive nature of the subject matter, the focus group methodology was the appropriate venue to elicit feedback (Madriz, 2003). 2.2 Industry and other private sector organizations A range of non-government advisory organizations informs industry or regulators of the best practice protocols for pipeline construction and operation. Both the industry operators and regulators work with these groups to aggregate engineering knowledge related to the safe operation of pipelines and define or outline what has been learned from incidents about how to operate and construct better and safer pipelines. This knowledge can also aid in identifying pipelines that may be at a higher risk of a future incident, something that is of particular concern as existing pipelines in the province continue to age. 2.2.1 CSA Group (Canadian Standards Association) The CSA Group, the Canadian Standards Association Group, is a not-for-profit company composed of representatives from industry, government, and consumer groups that develops and publishes standards in 57 separate areas, including pipelines. Born of the first world war, the 15 CSA Group was officially recognized in 1919 as the ‘Canadian Engineering Standards Association’ (CESA). It was charged with creating industry standards to guide and improve the safety of projects in a rapidly industrializing nation (CSA Group, 2019). While the company has broadened its scope to include various other industries over time, it is still the primary source of engineering regulations in Canada, accredited by the Standards Council of Canada (SCC) and the American National Standards Institute (ANSI). As a private entity, CSA standards are technically voluntary documents, unless referenced by a government or regulatory authority that compliance by an industry is mandatory (CSA Group, 2020). Compliance with these standards for pipeline construction and operation in BC has been made compulsory at the federal and provincial levels. Two specific CSA Group standards are relevant to natural gas pipelines in Canada. The first and foremost is the Z662 industry standard for the design, construction, operation and maintenance of oil and gas pipelines. Z662 is a 500+ page technical document created by a technical committee composed of over 250 volunteer committee members with expertise in the field and is supported by ten technical subcommittees and various working groups (CSA Group, 2016). The committee continually reviews the standards and releases revised copies as needed. Updates to the standards are informed by member experience, observed global failure trends, up-to-date academic insight from engineering and metallurgy studies, and the accident investigations resulting from a pipeline failure. As of 2019, the industry is expected to adhere to the 9th edition of the standard. In addition to Z662, BC mandates (under the provincial Oil and Gas Act, 2019) that all pipeline operators adhere to CSA Z246.2, the standard for Emergency Preparedness and Response for Petroleum and Natural Gas Industry Systems. To comply with this standard, all 16 operators must create and maintain an emergency management system that demonstrates the expected roles and responsibilities of all staff involved with a potential emergency response (BCOGC, 2018). They must also have available resources, including relevant equipment and space for an incident command post on standby. This system must be maintained with written records of all plans, training for staff and managers. In the event of an incident, an evaluation report will be done to assess any gaps in the response that needs to be addressed. 2.2.2 The Canada Energy Pipeline Association The Canadian Energy Pipeline Association (CEPA) has a significant advisory and information role in the Canadian pipeline industry. CEPA is a not-for-profit, membership-supported organization that works to represent the majority of natural gas and crude oil transporters operating in Canada. CEPA works to inform industry and the public on issues related to safety and regulatory initiatives (CEPA, 2020). The organization also act as a lobby group to comment on and advance policy to the government on behalf of their member companies. One of CEPA’s primary contributions to the evolution of the pipeline industry in Canada is the study and policy recommendations on Stress Corrosion Cracking (SCC). The group publishes the “CEPA Recommended Practices for Managing Near-neutral pH SCC” report. In its third edition, this report stemmed from their involvement in the NEB formal hearing into external SCC in 1995. Following a series of pipeline incidents in the 1990s caused by external SCC, it was deemed an extensive study was required to find the cause and remediation options available to prevent further incidents (CEPA, 2015). Along with the National Energy Board (NEB), CEPA promoted the study and use of pipeline coatings to improve pipeline safety and until recently continued to publish and update the SCC Recommended Practices Manual (CEPA 2015). While this manual is regularly cited and considered industry best practice, it is not 17 a required (by legislation) standard in industry or regulation. As of late 2021, the CEPA board of directors decided to cease operations after 28 years of operation and appears to be permanently closed. 2.3 Pipeline Government Regulators Regulators are either provincial or federal government ministries/departments or other agencies and commissions that support government planning and policy objectives to approve and permit, manage, or audit projects or enforce pipeline regulations. Depending on the regulator, they may be involved from inception to decommissioning of the project, or only for aspects of construction or operation. Regulator jurisdiction in BC is decidedly separated depending on the extent and size of the line. The following described groups all play a fundamental role in a pipeline’s lifecycle in BC but seemingly rarely overlap or work in coordination. 2.3.1 The British Columbia Oil and Gas Commission The primary authority responsible for all-natural gas extraction, processing, and transportation in BC is the BC Oil and Gas Commission (BCOGC). The BCOGC have jurisdiction over nearly all pipelines that operate within the province’s boundaries with a capacity of over 100 pounds per square inch pressure (psi). The BCOGC oversees the activities of all permitted oil, gas and geothermal activities, ensuring the industry has the appropriate plans, staff and abilities necessary to meet their regulatory obligations under the BC Oil and Gas Activities Act (2019). Since 1998, the BCOG has been the provincial ‘single-window’ regulatory agency responsible for oil and gas exploration, development, pipeline transportation and reclamation (BCOGC, 2020). Before the formation of the BCOGC, oil and gas activities in the province fell under the Department of Mines and Petroleum Resource jurisdiction under the 18 Petroleum and Natural Gas Act (BC Laws, 1996). Funding for the Commission comes from industry fees and levies. The Commission is not governed directly via a Minister but rather a Board of Directors (BCOGC, 2020b). Regardless of its quasi-independence, it is a ‘creature of the province,’ and its roles and responsibilities are defined by provincial law. In 1998 a study by Golder Associates, commissioned by the Canadian Association of Petroleum Producers found that the development of an Oil and Gas industry in British Columbia was restricted by the combination of unclear legislation with inconsistent application, a convoluted approval process and an overall lack of human resources (Rankin et al., 2000). Comparisons were made to other provinces, particularly Alberta, finding that the lack of one centralized body to oversee the industry in BC was inefficient. The ‘single-window’ format being proposed was seen as appealing to both regulators and industry and went from a Memorandum of Understanding signed by government and industry in February of 1998 to the passage of the Oil and Gas Act in July of the same year; a very swift policy change (Rankin et al., 2000). The intent was the single point of contact would streamline oil and gas operations in the province while simultaneously increasing government control over a profitable industry and fulfilling their obligations regarding Indigenous consultation (Rankin et al., 2000). The BCOGC can operate relatively independently from other provincial ministries, as it adopted a corporate model with self-determined financial and administrative control. It maintains authority over spill mitigation, property use and disposal, levies and negotiating agreements (Rankin et al., 2000). 19 2.3.1.1 What does the BC Oil and Gas Commission Regulate? Table 1.0. Provincial acts and regulations that are wholly or partially under the purveyance of the BCOBC (2020). Regulation / Act BCOGC’s Role Permitting and Authorizations Any company seeking to conduct oil and gas resource development in BC must retain a permit from the Commission with appropriate review and assessment. Heritage Conservation Act Government legislation used by the Commission to protect heritage resources. Geophysical Exploration Regulation Commission regulates geophysical exploration near pipelines, utilities, and residences. First Nations Consultation and Reconciliation The Commission is charged with fulfilling the Crown’s legal obligation to consult and accommodate where ‘appropriate’ on land use decisions related to oil and gas activities. Consultation and Notification Regulation Commission outlines how oil and gas companies communicate with people residing within a specific distance of oil and gas activities. Environmental Protection and Management Regulation Governments environmental objectives for resource management and ecological protection. Forest Act - Tree Cutting The Commission administers sections of this legislation to allow for land clearing. 20 Land Act Similar to the forest act, the Commission administers this section of the government legislation to allow producers to clear land for oil and gas development. Water Sustainability Act - Water flow in/out and stream crossings The Commission administers sections of government legislation and issues permits and licences so developers can access water, construct dams, change streams, etc. Oil and Gas Road Regulation This regulation gives the Commission the authority to regulate how resource roads are built, operated, maintained and decommissioned. Agricultural Land Reserve - Agricultural Land BCOGC has a delegation agreement with the Agricultural Land Commission to permit some non-farm uses on ALR lands for oil and gas development. Agricultural Land Reserve - Grazing Land The Commission administers sections of this government legislation to allow oil and gas development to clear grazing land for operations. Mines Act - Gravel/Borrow Pit The Commission has delegated authority under this government legislation to allow aggregate extraction for the oil and gas sector. Drilling and Production Regulation - Drilling/producing Allows Commission to regulate how oil and gas producers drill and complete wells, including spacing, protection from hazards, and safe disposal. 21 Pipeline Regulation Allows the Commission to regulate how oil and gas producers move oil, gas, water and related fluids in pipelines, incorporating national standards and consistent with other western Canadian jurisdictions. Liquefied Natural Gas Facility Regulation Allows the Commission to regulate how natural gas is liquefied, based on a national standard, and covers the entire life-cycle of LNG activities, including construction, operation, safety requirements and deactivation. Oil and Gas Processing Regulation A new regulation under development will regulate how oil is refined, and natural gas is converted into organic compounds such as plastics and fuels. Environmental Management Act Legislation that regulates environmental performance in the province, and the Commission administers specific sections for oil and gas producers related to surface and air discharges. Dormancy and Shutdown Regulation Regulation used to regulate how oil and gas activities are decommissioned and restored, including timelines to ensure and orderly close out of operations. Compliance and Enforcement The commission can issue non-compliance notices and warning letters, compliance order, make finding of contravention, issue administrative penalties or tickets, suspensions or cancellation of permits, and seek prosecution through the courts for companies operating outside of regulations. 22 Petroleum and Natural Gas Act Legislation that allows the Ministry of Energy, Mines and Petroleum Resources to regulate the bidding process for subsurface tenure rights and charge rents and royalties for the resources and requirements, well restoration and record-keeping. Drilling and Production Regulation - Hydraulic Fracturing, reservoir management, and unconventional wells Allows the Commission to regulate how oil and gas producers drill and complete wells, including spacing, protection from hazards, safety requirements, well restoration and records keeping. 2.3.1.2 BC Oil and Gas Act The Province of BC delegates regulatory responsibility to the BCOGC through the Oil and Gas Activities Act. Under the Act, the purpose of the BCOGC is (BC Laws, 2020): “(a) to regulate oil and gas activities in British Columbia in a manner that (i) provides for the sound development of the oil and gas sector, by fostering a healthy environment, a sound economy and social well-being, (ii) conserves petroleum and natural gas resources, (iii) ensures safe and efficient practices, and (iv) assists owners of petroleum and natural gas resources to participate equitably in the production of shared pools of petroleum and natural gas; (b) to provide for effective and efficient processes for the review of applications for permits and to ensure that applications that are approved are in the public interest having regard to environmental, economic and social effects; (c) to encourage the participation of First Nations and aboriginal peoples in processes affecting them; (d) to participate in planning processes; (e) to undertake programs of education and communication in order to advance safe and efficient practices and the other purposes of the commission”. As it reads, the Act is intended to protect and manage the development and long-term sustainability of an industry that is valuable to the Province. The Act then, in turn, guides the mission of the BCOGC. The BCOGC regulates oil and gas activities primarily by controlling the 23 permitting and approval of all oil and gas resource development within the Province. Private entities that wish to construct a facility, pipeline, conduct geophysical exploration, or market oil and gas must apply to the Commission for a permit through the online Application Management System (AMS). Applicants are required to include spatial, engineering, and technical data related to the project and a summary of consultation results with landholders and Indigenous Nations (BCOGC, 2020b). Additional information about land use, environmental metrics and archaeology may be required. With the ‘one-window’ design, there is an expectation of a rapid turnaround on permit applications. Indeed, the rate of project review in BC remains relatively high, with 669 new oil and gas-related applications approved in 2019 alone (BCOGC, 2020b). Where projects requirements may come up against other acts, like landscape changes near streams (licences issued under the Water Sustainability Act), or tree cutting to create new roads (Forest Act), special provisions are made under the Oil and Gas Act that allow the BCOGC to override other acts and issue permits (BCOGC, 2020b). 2.3.1.3 BCOGC Assessment and Consultation The BCOGC is required to help fulfill the BC government’s legal obligations to consult with Indigenous Nations on oil and gas projects. While some of the more notable projects, such as the Coastal Gas Link line, are large enough to trigger the provincial Environmental Assessment process, most do not, which closes that avenue of early and continued consultation. The reality of the BCOGC’s intentions to meet these obligations has come under criticism in past years. The single window system has been accused of limiting the time and capabilities of Indigenous Nations to work towards consent on development (Dagg, Campbell, and Simieritsch, 2011) and of enabling a damaging cumulative level of resource development in. This has been particularly pointed to in the Northeast of the province on the lands of the Treaty 8 First Nations 24 (Garvie & Shaw, 2014). Ongoing conflict, accusations, and a need for better fulfillment of the Commission's duty to consult have resulted in the creation of a ‘Long Term Oil and Gas Agreement’ between the BC Oil and Gas Commission (on behalf of the Province) and the Treaty 8 First Nations. The agreement codified the working relationship and understanding of appropriate consultation between the Commission and the Treaty 8 First Nations in northeast BC, working to improve the reporting process, consultation process, and incorporation of Indigenous Nations’ input into policy and regulatory development (Long Term Oil and Gas Agreement, 2016). This agreement is set to expire in March of 2022, and in the meantime only involves the member nations of Treaty 8. Under the normal course of operations, the duty to notify and consult is only triggered “if all or a portion of the First Nation’s Indian Reserve3 is located within the applicable notification distance” or “Any portion of the First Nation’s Indian reserve is located within the applicable consultation distance” (BCOGC Oil and Gas Activities Application Manual, 2021, pg. 272). In the 2019/2020 Strategic Plan (BCOG, 2020), a guidance document where the Commission outlines its strategies for the following years, the Indigenous Relations Strategy cites a planned initiative to implement the “Draft Principles that Guide the Province of British Columbia’s Relationship with Indigenous Peoples which encompasses UNDRIP and the Truth and Reconciliation Commission’s Calls to Action” (BCOGC Strategic Plan, 2020, pg 9). Implementing these objectives involves working with regional representatives to discern the impact of resource development on quality-of-life impacts and conducting surveys with Indigenous groups to understand better the opinions and attitudes toward oil and gas 3 This term is used in the Indian Act, an Indian Reserve is land held by the Crown “for the use and benefit of the respective bands for which they were set apart” under treaties or other agreements. It is a colonial term, which is noted here within the context of law or regulations. 25 development. In this report, the BCOG cites an internal 75% satisfaction rate with their current management approach to regulated activities and their impacts on Indigenous groups. The Commission has targeted an 87% satisfaction rate by 2021/22 (BCOGC, 2020a). This shift is reflective of the broader intent of the provincial government to promote better relationships with Indigenous nations and further reconciliation. 2.3.1.4 BCOGC Emergency Response Role In an incident response situation, the role of the BCOGC is primarily that of an observer. In an incident which could be an emergency, the permit holder (industry) is expected to take the lead and inform the BCOGC within an hour of the occurrence of an event. The BCOGC’s role is to provide coordination and support for major incidents. However, if they deem the permit holder to be clearly incapable, they are obligated to take over the initiation or leadership of the response (BCOGC Emergency Management Manual, 2020c). Active response falls to the permit holder, and industry is responsible for all costs associated with a response. The BCOGC (Province) will be reimbursed where necessary. The BCOGC also outlines the thresholds or ‘consequence levels’ that determine how an incident is rated in terms of severity. For example, where a natural gas release exceeds 2,000 m3 or the duration and volume of the release are unknown, the incident is automatically classified as a Consequence Level of 2 or higher (BCOGC Emergency Management Manual, 2020c). Under the Oil and Gas Activities Act (2008), operators are required to prepare and maintain an emergency response plan that meets the CSA z246.2 (Emergency Preparedness and Response for Petroleum and Natural Gas Industry Systems standard, described above). Within these regulations is the requirement for an Incident Command System (ICS) structure to be incorporated into all emergency planning documents. This puts the BC oil and gas industry in 26 line with federal and international emergency response bodies. The ICS system is increasingly adopted worldwide as a scalable systematic framework for response that easily incorporates multiple agencies where needed. The Commission, as part of its oversight role, provides guidance documents to industry related to ICS structure and expectations (BCOGC Emergency Management Manual, 2020c). The expectation of industry is for an emergency response plan to include training, written plans, and regularly scheduled exercises. The Commission requires its staff to attend these industry response drills and conduct evaluations. Suppose a permit holder exercise shows an unsatisfactory level of preparedness with deficiencies that could compromise public safety. In that case, there is a seven-day period for correction, then another exercise demonstrating competence must be held within 90 days (BCOG Emergency Management Manual, 2020c). The emergency management plans submitted by industry permit holders are expected to be updated and re-submitted yearly, as well after an incident that results in changes being made to the plan based on lessons learned from the response. 2.3.2 BC Utilities Commission Where the BC Oil and Gas Commission has regulatory authority over all pipelines that operate within the boundaries of the province with over 100 psi capacity, the remaining pipelines, those working at or below that threshold, fall under the jurisdiction of the BC Utilities Commission (BCUC). The BC Utilities Commission regulates all of the smaller natural gas distribution systems to homes and businesses, as well as the feeder lines that connect larger processing facilities. Under the Oil and Gas Activities Act (2019), the BCUC establishes tolls and conditions of service for intra-provincial oil pipelines. 27 The Utilities Commission is similar to the Oil and Gas Commission as it operates independently on behalf of the province. Some have noted that the continued development of LNG facilities in the province of BC may prompt the BCUC to take a more significant role in the economic regulation of natural gas and upstream processing facilities (Ostergaard et al., 2014). 2.3.3 WorkSafeBC WorkSafeBC is a provincial agency that operates as both a safety regulator and a workplace insurance company. Their mandate includes education, prevention, compensation and support for injured workers (WorkSafeBC, 2020). For natural gas pipeline projects, WorkSafeBC has OHS jurisdiction over all pipelines located entirely within the province during all phases of the lifecycle of a pipeline and response. Field officers will periodically conduct inspections to ensure that site safety plans are complete and up to date. They also check that site inspections are being completed by operators regularly with solid documentation and response drills are being conducted. All incidents must be thoroughly investigated and reported (WorkSafeBC, 2008). Before any new pipeline construction can begin, permit holders are required to submit a Notice of Project (NOP) to WorkSafe BC and a forestry NOP wherever tree falling might occur. Most tasks in the pipeline construction process relate directly to a section of the Occupational Health and Safety Act (2020), which WorkSafeBC is mandated to enforce. 2.3.4 Environmental Assessment Agencies Environmental Impact assessment (EIA) is a decision-making tool based on scientific observation that predicts and evaluates a project's impacts on the environment (Therival et al., 2013). The process is often enshrined in national legislation and regulatory structures. EIAs depend on scientific inputs from a range of disciplines at each stage of the process. This includes scoping, collection of baseline data, estimating or predicting impacts, developing mitigation 28 measures, evaluating risk, creation of monitoring programs, and reviewing relevant technical and scientific reports (Jacob et al., 2018). Mitigation strategies are intended to be suggested only if detrimental environmental effects cannot be avoided. EIA applications are also intended to measure the impacts of the project beyond initial construction; it needs to consider the impact within the context of development in the region (cumulative effects) and the broader environment (greenhouse gas emissions) (CERI, 2016). In Canada, pipeline projects of a large enough scale will trigger the requirement from the government for an environmental impact assessment. Provincially, an environmental impact assessment will be required if the proposed pipeline is of a diameter of greater than 114.3 mm and a length of greater than 60 km. If the pipeline diameter is larger, the length threshold decreases. A federal EIA is required for a designated project with includes any new international or interprovincial oil or gas pipelines with a length of more than 75 km or are in a new right of way. Whether the assessment is conducted by the Impact Assessment Agency of Canada (IAA) or the BC Environmental Assessment Office (BCEAO) is determined, like other pipeline regulations, by whether or not the pipeline will cross provincial or international borders. In some circumstances the agencies may work collaboratively, or the federal process may be substituted to the provincial act (BCEAO, 2015). Both the provincial and federal environmental assessment Acts have been revised in the last couple of years. For both groups, there had been increasingly vocal criticism of inefficiencies in the process and weaknesses regarding the requirements for, and the quality of, science and evidence in the EIA process (Westwood et al., 2019). In revitalizing the BCEAO, the province hopes to better address their responsibilities and the needs of all Indigenous rights holders, the public, and industry stakeholders (BCEAO, 2019). For the public, changes include enhanced clarity and transparency along with earlier and greater 29 opportunities for engagement. For Indigenous nations, the BCEAO seeks to support reconciliation and the implementation of the UNDRIP through increased Indigenous nation participation in the assessments, the inclusion of traditional knowledge and seeking Indigenous consent at multiple points during the process. Allowances made for industry include increasing the efficiency of the assessment process and the provision of early, clear direction on the application. The provincial EIA process will only be initiated for a pipeline project entirely within the province of BC that is above the threshold defined by the BCEAO for reviewable projects. The thresholds for a new project are: “(1) Subject to subsection (2), a new transmission pipeline facility with (a) a diameter of 114.3 mm and a length of 60 km, (b) a diameter of between 114.3 and 323.9 mm and a length of 50 km, or (c) a diameter of > 323.9 mm and a length of 40 km, if the land on which the pipeline is built is not alongside and contiguous to an area of land previously developed for a transmission line, transmission pipeline, public highway or railway” (BCEAO, 2019) So, similar to determining the jurisdiction over pipelines, the requirement for an EIA in BC is entirely determined by the capacity of the structure. If the proposed project is too small to meet these requirements the permitting process will remain entirely in the hands of the BCOG. For proposed pipelines outside the provincial jurisdiction, the IAAC is responsible for fulfilling the mandate of the Impact Assessment Act (2019). This is triggered by a pipeline application that will cross a border, involves a federal authority or lands, or where a federal authority is providing funding (IAA, 2019). In recent years, most of the more controversial pipelines have fallen into this category (TransMountain, Energy East, Keystone XL). These projects are assessed by either a responsible authority or by a review panel (IAA, 2019). A 30 project falling under federal jurisdiction will trigger an EIA by either being identified as a ‘designated project’ under the Act or by ministerial designation (IAA, 2020). The repeal of the 2012 Canadian Environmental Assessment Act and subsequent enactment of the Impact Assessment Act (2019) increased opportunities for early engagement with stakeholders, streamlined the assessment process, enshrined the use of scientific and Indigenous knowledge, improved accountability, and incorporated concepts like sustainability and gender-based analysis into the process (IAAC, 2020). As it coincided with creating the Canadian Energy Regulator (CER), there was also increased integration of the EA process into energy projects. Mitigation is a critical component of the environmental assessment project for pipelines. Often, where available, applicants may try to take advantage of existing access roads or hydro right of ways to minimize habitat disturbance. Other options to reduce adverse habitat effects could include locating the pipeline route along previously disturbed areas to minimize fragmentation, using alternative timing for the project activities, or compensating habitat loss by establishing offset areas of equivalent or better habitat quality (CERI, 2016). Applicants may also need to be prepared to choose an alternative pipeline route entirely, which can be a costly proposal. There has been an increase in the concern for regional cumulative effects and greenhouse gas emissions in both the provincial and federal EA processes, a consistent concern expressed for natural gas pipeline projects from the public and Indigenous Nations. Significant potential for cumulative adverse effects on caribou has been the cause of a high significance rating in EIAs for three of the more prominent natural gas pipeline applications of the last few years (Westcoast Connector Gas Transmission, Prince Rupert Gas Transmission, and Coastal GasLink 31 Pipeline)(CERI, 2016). The BC EAO was unconvinced for the projects that mitigation measures would be enough to reduce the potential impact to a non-significant level (BC EAO 2014). The reviews of the same pipeline projects also concluded that the habitat and sensory disturbance were likely to interact with foreseeable projects to create cumulative effects at an unacceptable level (CERI, 2016). Environmental assessments of proposed pipeline projects in BC are also under some pressure, both from internal environmentalist lobby groups and external (international) regulators, to consider the impact of pipeline projects on the development of an industry linked to greenhouse gas emissions. Adverse Green House Gases (GHGs) effects have been a significant environmental issue reported from the proposed natural gas pipeline and LNG projects, with several projects reviewed by the BC EAO or IAA citing them (CERI, 2019). In the United States, lawsuits against the Keystone XL pipeline, which was intended to transport oil from western Canada to the US, argued that the environmental assessment failed to account for how the pipeline would encourage both oil use in the US, and oil production in Canada (Coleman J, 2018). Despite the state department's decision that not only was it beyond the scope of an environmental assessment to determine the appropriateness of foreign energy production, and in fact the pipeline may have reduced carbon emissions by replacing truck and locomotive transport, President Obama, ceded to increasing and insistent pressure at the time and reversed the decision to allow the pipeline to go through (Coleman J, 2018). However, these lawsuits have set a precedent that continues to increase the controversy surrounding pipeline projects in BC and abroad. 32 2.3.5 CER (Canadian Energy Regulator, formerly National Energy Board (NEB)) The primary regulator for all federally regulated pipelines, that is the ones that cross provincial or international borders, is the Canadian Energy Regulator (CER) which today regulates over 73,000 km of pipeline (CER, 2020d). CER, formerly known as the National Energy Board (NEB), evolved out of the rapid oil and gas industry growth and national tensions in the 1950’s (Lucas, 2018). Public and political controversy surrounding fuel costs and west vs east regional rivalries surrounded natural gas pipeline proposals at the time. The result was in 1959, parliament established the NEB, which would continue to regulate oil and gas transportation via pipelines for the subsequent 60 years. The NEB’s oversight of Canada’s pipeline infrastructure has not been without controversy. In particular, there have been significant changes to the environment in which Canada’s pipelines operate in the last decade. Growing public opposition due to climate change and other environmental concerns, greater demands for public participation in pipeline decisions, increased Indigenous communities frustration with involvement in the assessment process, and provincial governments asserting their jurisdiction all came to bear on the traditional operation of the NEB (Lucas, 2018). Critics accused the NEB of failing in its duties to consult particularly with Indigenous Nations, citing supreme court rulings that suggested the NEB’s role as a quasi-judicial body in the regulatory process meant it had a different relationship to Indigenous people than the Crown, one that was confused by its own institutional and regulatory objectives (Popowich, 2007). Stakeholders from all sides were frustrated with NEB policies that were ambiguous and fluid, that it left the onus of interpretation on the stakeholders alone. Some were also frustrated with the nearly 100% approval rate of all projects that came before the board (Grabben & Sinclair, 2015). 33 The NEB was also increasingly being pulled before the courts. Court cases that challenged the NEB’s consultation performance included Chippewas of the Thames First Nation v. Enbridge Pipelines Inc. et al., (Supreme Court of Canada, 2017). The case centered on an expansion of Enbridge’s existing Line 9 in southern Ontario through the traditional territory of the Chippewas First Nation. While the supreme court of Canada at the time determined that the engagement through the NEB assessment process was adequate based on the scope of the project, the Chiefs of Ontario denounced NEB decisions that allowed for the historical pattern of unilateralism that failed to recognize the First Nation’s sovereignty and did not adequately perform the duty to consult in line with the intent of the Niagara Treaty, making the decision a failure of energy justice (Hurlbert & Rayner, 2018). Another important legal decision that contributed to the discourse surrounding the NEB’s failure to consult was the decision of the Federal Court of Appeal to overturn the NEB’s approval of the Kinder Morgan Trans Mountain Pipeline expansion project. The courts held that the federal government had failed in its duty to meaningfully consult First Nations in the EA process (Tsleil Waututh Nation et al. v. Attorney General of Canada et al. 2018). There was also pushback against the NEB from industry. Prior to its dissolvement, the federal government had altered the regulatory decision-making process with legislation in 2012. It required that all decisions made by the NEB, including rejecting proposals, would have to come before cabinet for review and possible variance, which included the possibility of overturning NEB decisions and referring terms and conditions back to the board for further reconsideration (Cleland & Gattinger, 2017). In 2016 the government also enacted new interim measures for major energy project proposals which included additional consultation processes to be undertaken by the government in addition to NEB hearings, and the inclusion of upstream 34 greenhouse gas emissions from the production of fossil fuels in the final decision after the NEB review process. These additional provisions added to the existing NEB decision making process added substantial uncertainty and made it unclear on what basis the government would or would not approve a project (Cleland & Gattinger, 2017). These concerns finally culminated in an Expert Panel report (NEB, 2017), that the federal government commissioned for the modernization of the NEB and the federal Environmental Impact Assessment Act which eventually led to the creation of Bill C-69 in August of 2019. Bill C-69 enacted the Canadian Energy Regulator Act (2020), establishing the CER and outlining its mandate, composition, and role: “to regulate the exploitation, development and transportation of energy within Parliament’s jurisdiction” (Parliament of Canada, 2018). CER as outlined in the Act (2018): “(a) provides for the establishment of a Commission that is responsible for the adjudicative functions of the Regulator; (b) ensures the safety and security of persons, energy facilities and abandoned facilities and the protection of property and the environment; (c) provides for the regulation of pipelines, abandoned pipelines, and traffic, tolls and tariffs relating to the transmission of oil or gas through pipelines; (d) provides for the regulation of international power lines and certain interprovincial power lines; (e) provides for the regulation of renewable energy projects and power lines in Canada’s offshore; (f) provides for the regulation of access to lands; (g) provides for the regulation of the exportation of oil, gas and electricity and the interprovincial oil and gas trade; and (h) sets out the process the Commission must follow before making, amending or revoking a declaration of a significant discovery or a commercial discovery under the Canada Oil and Gas Operations Act and the process for appealing a decision made by the Chief Conservation Officer or the Chief Safety Officer under that Act (Parliament of Canada, 2018)” The Act makes it clear that for federally regulated pipelines, CER is responsible for overseeing a pipeline’s life cycle. All new pipeline projects now have to file an application with 35 the CER that will include, at the least, information on the pipeline construction, safety measures to protect workers and the public, plans to minimize environmental damages, and how the company has addressed the interests of all people affected by the pipeline’s construction (CER, 2020). The CER assesses pipeline applications to determine whether the project is in the Canadian public interest. This clause of ‘public interest’ was in the constitution of the NEB as well and has historically been a point of contention. Hierlmeier (2008) identified six varying definitions to the concept: 1. Common interest, where a matter such as public safety or morality are considered universally acceptable across all aspects of society. This definition is critiqued for being too general or vague to be particularly helpful. 2. Majority interest, where the theory of the good of many outweighs the good of all comes into play. A definition that is contested for being overly weighted towards the maintenance of the status quo, ignoring minority views and specialist knowledge in the process. 3. Balance of interests which describes a compromising position that often involves a cost-benefit analysis. Issues arise with this definition in that it is most ascribed after a decision has been made and provides no guidance for further decision-making processes. 4. Public interest as a morally superior standard where the issue is measured against a morally or scientifically rigorous standard. Issues with this definition can arise from personal moral biases outweighing public opinion or a lack of data invalidating scientific measures. 5. Economic interest, which is a capitalist definition most found in western societies where the generation of wealth is seen as a benefit to all and can therefore be defined as for the common good. 36 6. Shared values, which refers to the fundamental values shared in a socially minded society. An example of these would be the values protected by the Canadian Charter of Rights and Freedoms. 7. Fair, transparent procedure, which rather than being based on substantive data, references the concept that if the established and fair procedures are followed then the subsequent decisions will be automatically reflective of the common good. There is no clear agreement on the meaning of “public interest’ in either academic or regulatory documents, making it a challenging concept to apply without inducing controversy. Discourse over the definition of public interest has been occurring in North American philosophy, politics, and policy since the 1930s (King et al., 2010), however remains frustratingly intangible, or at least divisive. Historically the NEB defined public interest in terms of a project's public benefits balanced by the negative impacts, including factors such as environmental effects, consequences to landowners, economic effects and the efficient use of resources (Joseph et. al., 2020). Other aspects of Canadian pipeline policy development and operational decision making that grapple with the public interest are the environmental assessment agencies whose decision making has been critiqued in the past for being heavily weighted on the economic factors in public interest determinations (Hierlmeier, 2008). For the revitalization of permitting under the new Canada Energy Regulator, timelines for the review of permit applications have been solidified to make the process more reliable for stakeholders. Applications for pipelines of less than 40 km are expected to be assessed within 10 months, while longer pipelines will be assessed within 15 months and recommendations forwarded to the federal Cabinet with whom the decision to issue a Certificate of Public Convenience and Necessity rests (CER, 2019). To manage the permitting process, the CER must 37 form a commission that will review all permit applications and make recommendations to the regulator; it must consist of up to seven full-time commissioners, one of which must be an Indigenous person. One significant change in the shift from the ‘NEB model’ to the CER, is the joint commission of the CER and IAAC in assessing larger pipeline projects. Previously, the NEB was the main authority for issuing pipeline approvals. The new legislation removes some of the discretionary decision making, listing four economic and financial factors to be considered related to environment, health, Canadian society, and Indigenous peoples (Lucas, 2019). These guidelines also require the consideration of cumulative effects in any project reviews. The CER ensures engineering, safety, and environmental requirements meet the Onshore Pipeline Regulation and standards (OPR) laid out by the CSA through audits and site inspections (CER, 2019). A review of the OPR has been initiated in the CER regulatory plan to be completed between 2020 and 2022. The CER participates in the Impact assessment implementation committee at three separate levels, deputy minister, assistant deputy minister, and director general, who participate in monthly meetings. Beyond the initial permitting process and construction of pipelines, the CER is also responsible for the monitoring, assessment, and review of the pipeline's operations for the length of time it is in service. This role is done through regular inspections, audits, and investigations to make sure the pipeline operators are in compliance with operational safety requirements and are maintaining a dedicated response capability as outlined in the CSA standards (CER, 2020a). If there is Indigenous interest in a project, the CER may involve them in a monitoring role for the project. Any companies found to not be operating within the regulations are subject to immediate enforcement action. The decision of when and where to conduct inspections is based on a ‘risk-38 based’ system that analyses data about the facility, company history and location to identify the projects of most concern (CER, 2020a). The regulatory responsibility for pipelines carries on beyond its working life. If a pipeline is abandoned in place, it continues to regulate the pipeline and requires industry to monitor and report on them (CER, 2019). The CER regulates the tolls on federally regulated pipelines as well as the export and import of natural gas. The CER Commission monitors the market for natural gas and LNG, including the performance under existing export authorizations. This maintains a balance so the quantity of gas and natural gas liquids exported will not exceed the surplus remaining after Canadian requirements have been met (CER, 2020d). They are also responsible for enforcing Part II of the Canada Labour Code on behalf of all workers in the field and monitoring third-party excavation near pipelines. While the CER does investigate pipeline incidents to see if regulations were being followed, the majority of the accident investigation process is done by the Transportation Safety Board. 39 Figure 2.1. Flowchart of regulation during the application, construction, and operational phase of a pipeline project in British Columbia The way the legislation is laid out, and indeed in how guidance documents appear, from an external perspective it would seem that the CER operates in a silo. That is to say that it has very little interaction with the provincial counterparts that regulate the natural gas pipeline activities in the province of BC. But in discussions and the focus group with the CER, it was noted that there are a number of formal and informal mechanisms that exist to facilitate cross agency and industry information sharing and even resource sharing. For formal information sharing, the CER has legislation that permits ministers to request a study be conducted on any particular topic where the findings can be related to industry. The CER also has extensive MOUs (Memorandums of Understanding) in place with provincial agencies such as BCOGC or BC Energy and Mines, that are formal arrangements that, while not legally binding, usually involve 40 the sharing of resources or deferment of authority where it makes sense. At a step above MOUS, the CER also maintains approximately 7 Service Agreements, which unlike MOUS, are legally binding and involve an exchange of money, with other agencies. An example of an active Service Agreement would be the agreement that the Transportation Safety Board is the primary authority for accident investigations. Information sharing with regulators also occurs at the Western Regulators forum, a group made up of oil and gas regulator representatives from the provinces of Western Canada. The group works meets to discuss the use of standards in regulations, performance measures and areas where multilateral support is possible. Discussions with CER also highlighted that cross agency work also occurs at somewhat informal levels. Both oil and gas spill responses and training exercises bring together multiple agencies, both federal and provincial along with industry representatives to work together and share learnings. These are also opportunities for informal relationship building and meetings to occur. The CER promotes additional dialogue and learning with industry through the involvement in think tanks, public policy forums, and educational initiatives and conferences such as CAMPUT which is a self-supporting non-profit association that consists of energy and utility regulators from all federal, provincial, and territorial bodies. In addition to working across Canada, the CER is also responsible for dialogue that occurs internationally with the US Energy Information Administration (EIA), which holds multiple meetings a year to discuss issues such as pipeline capacity and energy forecasts. To further this relationship, the CER participates in a staff sharing program with the EIA, where members exchange jobs to learn from and improve understanding at their international counterpart agencies. 41 2.4 Responders In this research, responders are agencies that have few if any responsibilities over the initial permitting or oversight over day-to-day operation of pipelines. These groups are only involved in the event of a pipeline failure, which would be in an emergency response or accident investigation capacity. 2.4.1 B.C. Ministry of Environment & Climate Change Environmental Emergencies Department As was noted earlier, in accordance with the CSA standard Z246.2, pipeline operators are required in BC to maintain emergency plans and equipment to respond to an incident. In the event of an incident, the province also deploys its own emergency responders. In BC, the Ministry of Environment’s Environmental Emergency Program (EEP) is expected to respond to any hazardous materials spills that occur, a responsibility that goes well beyond just pipeline incidents. The EEP implements the Environmental Management Act and all applicable regulations on behalf of the province (BC Laws, 2020). A provincial regulatory body enforcing the Act is not consistent across the country, with some provinces may rely on federal bodies such as the Transportation Safety Board (TSB) to maintain compliance (BC Ministry of Environment, 2020). The program has three sections: preparedness & policy development, response, and recovery (BC Ministry of Environment, 2020). The preparedness aspect mostly involves policy analysts and the creation and updating of standard operating procedures (SOPs), legislation, and engaging with industry through the involvement in exercises. In the event of an incident, the program deploys Environmental Emergency Response Officers (EEROs) and other support staff to oversee and provide guidance to the spiller to ensure that appropriate actions are being taken 42 (BC Ministry of Environment, 2020). Staff are located strategically around the province. After the initial response, during the recovery phase, specialists are on hand to ensure at-risk species are identified and accommodated, and environmental restoration is performed as needed. While active in response, the primary roles of the EEP are to act as an expert advisor, provide provincial regulatory oversight, technical recommendations and to act as a liaison body between the spillers and other public, municipal, or Indigenous bodies. 2.4.2 Transportation Safety Board (TSB) Unlike provincial pipelines where an operator (company) is expected to conduct their own accident investigation, federal pipelines incidents are under the jurisdiction of The Transportation Safety Board of Canada (TSB). The TSB is the primary federal agency in Canada for the promotion of safety in air, marine, pipeline, and rail transportation and was formed by an Act of Parliament (the Canadian Transportation Accident Investigation and Safety Board Act) in 1990. A key quality of its structure and operations is its independent nature. Intended to instil public confidence, the TSB reports directly to Parliament through the President of the Queen’s Privy Council and has no direct function in assigning civil or criminal liability (TSB, 2020). As the determination of causation in transportation accidents can have an adverse effect on both government and industry, there is the potential for institutions or individuals to attempt to influence the outcome of an investigation. It is for this reason that the body responsible for any accident investigation should be strictly independent with the sole objective of protecting and promoting public safety. Under Canadian law, the TSB has sole jurisdiction to investigate incidents in rail, marine, air and pipeline industries, collecting relevant data and distributing the results of those investigations (Simpson, 2006). As per their mandate, the TSB will conduct investigations into 43 transportation incidents, including public inquiry where necessary, to identify the underlying causes that led to an event (TSB, 2020). All resulting investigation reports are made publicly available including an annual report of all the occurrence statistics. To further the reliability of the information gathered by the TSB, there are serious consequences to the impedance of an investigation. Lying to or obstructing a TSB staff member investigating an incident is considered grounds for indictment under the Canadian Transportation Accident Investigation and Safety Board Act (2020). In the case of pipelines, a Memorandum of Understanding (2011) exists between the CER (formerly NEB) and TSB where in the event of an investigation, TSB findings will always surpass those of the CER, and the CER is precluded from investigating an occurrence if it has already been investigated by the TSB. A memorandum of understanding is a bilateral agreement between two parties that outlines agreed upon roles and actions to be taken by both parties. In the case of the MOU between the CER and the TSB, it makes it clear that the investigation findings of the TSB will be considered the official findings that are used for determining cause and fault for the incident. For pipelines in BC, it should be noted that the TSB will only investigate incidents that involve federally regulated pipelines. All investigations conducted by the TSB follow an accident causation model referred to as the Integrated Safety Investigation Methodology (ISIM) that consists of three key steps (Katsakiori et al., 2009). The TSB developed the ISIM to incorporate both the safety analysis of equipment as well as the interaction points between the human and the system components that are controlled by managerial, design, regulatory and other procedures (Ayeko, 2002). ISIM provides a holistic framework for accident investigation that encourages accident investigators to assess the risks associated with safety deficiencies to prioritize safety issues representing the highest risks. The foundational precept for ISIM is that accident prevention should reflect a 44 realistic analysis of risks rather than strict compliance with prescriptive rules, standards, and regulations (Ayeko, 2002). The process takes a multi-pronged approach to mitigate the risk of normal human errors, with the understanding that purely enforcing strict compliance with rules is insufficient for understanding the root cause of incidents and translating those learnings into future gains in safe behaviour. The first step in the ISIM process is the collection of information about all the factors, personnel, and equipment needed to construct a timeline of the event and any underlying conditions. The second is to identify the level of risk associated with each task of the assignment and what sort of preventative measures or barriers were in place. After discovering safety deficiencies, all available options for risk control are considered. This style of accident investigation that works to discover underlying causes and failures that go beyond frontline workers and equipment failure is an evolving practice that is redefining workplace safety beyond just the oil and gas industry (Lundber et al., 2009, Hale et al., 2012, Kletz (2006). Transport Canada manages the application of the Transportation Safety Board Regulations (2020) across all transportation industries and relies on operators to obey explicit reporting requirements. From the Regulations (2020) regarding Occurrences: “4 (1) The operator must report any of the following pipeline occurrences to the Board: ○ (a) the pipeline sustains damage that affects the safe operation of the pipeline as a result of another object coming into contact with it; ○ (b) an unauthorized third party activity affects the structural integrity of the pipeline; ○ (c) a geotechnical, hydrotechnical or environmental activity poses a threat to the safe operation of the pipeline. Report — occurrences caused by operation (1.1) The operator must report any of the following pipeline occurrences to the Board if they result directly from the operation of the pipeline: ○ (a) a person sustains a serious injury as defined in section 1 of the National Energy Board Onshore Pipeline Regulations or is killed; 45 ○ (b) there is a fire, ignition or explosion that ■ (i) affects the safe operation of the pipeline, or ■ (ii) poses a threat to the safety of any person, property or the environment; ○ (c) there is an occurrence that results in ■ (i) an unintended or uncontrolled release of hydrocarbon gas, ■ (ii) an unintended or uncontrolled release of HVP hydrocarbons, ■ (iii) an unintended or uncontrolled release of LVP hydrocarbons in excess of 1.5 m3, or ■ (iv) an unintended or uncontrolled release of a commodity other than hydrocarbon gas, HVP hydrocarbons or LVP hydrocarbons; ○ (d) there is a release of a commodity from the line pipe body; ○ (e) the pipeline is operated beyond design limits or any operating restrictions imposed by the National Energy Board; ○ (f) the pipeline restricts the safe operation of any mode of transportation.” A clear distinction is made within TSB documentation between ‘occurrence’, ‘reportable occurrence’, ‘incident’, and ‘accident’. An occurrence is any transportation event that is determined by the Canadian Transportation Accident Investigation and Safety Board Act, while a reportable occurrence (as shown above) is defined by the Transportation Safety Board Regulations (TSB, 2019). Incidents vs accidents, which is a contestable definition across the health and safety industry is outlined for each individual facet of the TSB’s jurisdiction (marine, air, train and pipeline). In health and safety literature and documentation the concepts of the incident versus the accident have historically been used either as interchangeable terms or to denote the seriousness of an event. Therival (2018) stressed that hazards, or a source of danger that potentiates risk (Therivel, 2018), have the potential to initiate both incidents and accidents. While others such as Drupsteen, Groenewg & Zwetsloot (2013) felt that an incident refers to the sequence of actions or events leading up to the impact or a “near-miss”, and an accident refers to the harmful consequence(s) that may occur as a result of these actions or events. In this way, not all incidents are accidents, however, all accidents are incidents. Similarly, an attempt to unify risk terminology by Christensen et al. (2003) suggested while both terms reference an event, an 46 incident can be an isolated or number of interrelated circumstances that may or may not result in an accident which is a singular event typically related to an engineering risk. There is further dialogue, particularly in road safety that the term accident is problematic as it implies a lack of responsibility or fault (Stewart & Lord, 2002). For the TSB, a pipeline accident is defined as an event where: a person is harmed or receives serious injury, the safe operation of the pipeline undermined by damage related to contact or an explosion, or there is a product release from the line pipe body (TSB 2019). Meanwhile an ‘incident’ is an event that involved an unintended or uncontrolled release of product (not from the line body), the pipeline is being operated beyond its limits, or there is activity (geotechnical, 3rd party, environmental) that poses a threat to the safe operation of the pipeline (TSB, 2019). 47 Figure 2.3. Spill response flowchart for federally regulated natural gas pipelines in BC. Figure 2.2. Spill response flowchart for provincially regulated natural gas pipelines in BC. 48 2.5 Analysis The many of entities, acts and regulations that are involved with the construction, operation, and incident response of Natural Gas pipelines in BC can make the regulatory landscape difficult to interpret. To add to the seeming complexity, this set up is unique to BC. Each province in Canada will have its own arrangements, depending on the provincial acts and bodies that are in place. This can, and has, led to confusion during a pipeline incident about who exactly is ‘in charge’. What should be clear is that there are two discrete modes that pipelines operate in BC; federally and provincially regulated. From an external perspective it seems like these projects operate parallel to each other in their own discrete industries, rarely intersecting at a regulatory level. Reality is more complicated. To provide greater insight into how regulators and industry intersect, focus group discussions were held with both the BCOGC and the CER. This provided a unique opportunity to hear from senior members of the agencies on how communications worked in reality, what was in development and what were the ongoing challenges that are being faced in the industry as regulators. The questions that were asked were: • What formal mechanisms exist to support and facilitate communication between the agencies or other organizations working in the pipeline sector? • Are there examples of informal mechanisms that can be described? • Are there examples of where the agency has shared resources with another agency working in the sector to meet a common need or even help with the specific needs of another agency? Both agencies referenced formal communication methods that promoted communication both among different provincial or federal ministries as well as across jurisdictions. For the BCOGC 49 within the BC government, there is a Deputy Minister Commission for Natural Resources Task Force, which is a long-standing committee that covers cross ministry issues as they relate to oil and gas. For the CER, within the federal sphere, they participate in the Impact assessment implementation committee as well as monthly meetings of the Major Project Management Office. Each regulator also manages several memorandums of understanding with other agencies, groups, and Indigenous Nations. The CER has nearly 75 such agreements in place and the BCOGS has approximately 27. MOUS exist between the CER and the BCOGC for the BCOGC to provide first response support where the CER may not have coverage. The BCOGC also has MOUS to act as enforcement for other agencies mandates, issuing licences, and structuring relationships over common concerns with groups like the EAO. The third vein of formal communication comes in the form of participation in broader industry regulator information sharing groups such as the Western Regulators Forum, where the BCOGC along with regulators from Alberta, Manitoba, and Saskatchewan work together to find common ground, increased standardization, and to compare performance measures. Both regulators are also involved in industry organization led initiatives such as CEPA, CSA technical committees, and the Canadian Association of Petroleum Producers (CAPP). While the involvement in these groups shows an agency commitment to communicating challenges and technical issues in a formal issue, the focus group discussions alluded to a significant portion of inter-agency communication and work being done at an informal level. Informal communication provides opportunities to share information and lessons learned among peers in a way that issues can be ‘workshopped’ towards solutions. The CER shared their involvement in a variety of information sharing avenues including the Centre for Educational 50 Research and Innovation that is a sub network of regulators that sets the current thinking of how to effectively implement regulatory policy in the country. They also participate in a variety of think tanks and public policy forums with other regulators such as Transport Canada and Health Canada which are intended to bring operation level people into conversations around policy improvement. Knowledge transfer also occurs internationally, with the CER meeting every 3-6 months with the US Energy Information Administration to share market forecasts, and pipeline capacity. In focus group discussions, both agencies, but particularly the CER stressed their commitment to increasing transparency of their operations. This will include the increased authority to penalize companies for non-compliance in evolving legislation. There have been, historically, challenges to the strength of accountability that agencies hold gas companies to in the face of incidents and non-compliance. Both federal and provincial pipeline regulatory agencies, as well as bodies like WorksafeBC can leverage fines and penalties for failure to adhere to established safety requirements. Additionally, in Canada, pipeline companies are 100% liable for damages caused by an incident. These monetary incentives are positive drivers for accountability. However, some may argue that this leverage to enforce private industries adherence to existing rules does not go far enough. Financial penalties often represent a fraction of the profits from a large corporation, and while existing legislation provides funding to remediate environmental concerns after an incident, detractors argue that pipeline companies are not held sufficiently accountable for the cumulative effects of their development and operations (Joseph et al., 2017; Murray et al., 2015). This notion of a broader accountability to the environment beyond individual pipeline projects is quickly gaining traction and is being increasingly reflected in the environmental assessment policies for current and future projects. 51 Both agencies stressed the improvements that have been made to industry safety and their intent to share information as it relates to safety across the industry. A very positive aim of the industry in this aspect is the commitment to research from both government regulators, and private industry groups such as the CSA. Significant research has been done in Canada to promote and understand the metallurgical consequence of our operating environments and how this effects the safety of a pipeline. Incentive for this research has largely come from incidents, which will be explored further in the fourth chapter of this Thesis. In focus groups with both federal and provincial agencies for this thesis, there was an affirmation of the commitment to prioritizing research for the future. This included the greater involvement of academic resources such as universities to analyze the data being collected by agencies. This diversification of research may aid in future challenges to best practice that in turn, will promote the evolution of the industry towards better, safer operations. There remain challenges within the agencies. While both the BCOGC and the CER in discussions pointed to the multitude of existing MOUS in place to support capacity and information sharing, both agencies also expressed that many to most of those MOUS were outdated and in need of review. There is a limited capacity within the agencies, challenged by extensive workloads and other pressures, to revisit dated agreements until they are pressing. As well for the CER, most formal agreements were created under the former NEB which represents a significant body of work requiring updates. Another enduring legacy of the NEB, reflective of broader politics, is the provincial vs federal energy conflict. Domestically, the politics of pipelines in British Columbia do not reflect those of the federal government, let alone those in the neighbouring province of Alberta. These conflicts of interest challenge the integration of regulatory policies between jurisdictions. Internationally, regulators must also navigate 52 difficulties that arise from shifting priorities south in the United States that influence and challenge the integrated North American Market. 2.5.1 Conclusion From my work, it can appear based on readily available information that there is a sharp divide (even siloes) between the work done by federal regulators and their provincial counterparts. Even within provincial jurisdiction, there are diverse responsibilities across agencies and at different stages of the pipeline life cycle that would seemingly have little opportunity or cause to interact. The discussions held in the focus groups organized for this thesis, however, show a different image. Federal and provincial and provincial agencies maintain a variety of communication streams, both formal and informal, where information is shared, and lessons learned are disseminated and communicated between agencies and between levels of government, and there is ongoing collaboration and cooperation. This is particularly true during environmental or industrial incidents such as oil spills or natural gas pipeline ruptures, where the emergency response capacities of all relevant agencies are brought to bear in a cooperative fashion to resolve and mitigate the effects of the incident. Both the BCOGC and the CER referenced incidents as a something that engenders the sharing of information and resources with other agencies and industry. Pipeline incidents bring together representative across the industry, often working side by side with members of different agencies to manage effects, discern cause(s), and prevent future occurrences, elements which are discussed in the next chapter. Aside from the learnings across the pipeline industry in BC that can be clearly discerned from the increased quality of incident reporting, and the more rigorous standards for training and emergency preparedness, there are many initiatives that are less obvious. In discussions with both the CER and BCOGC as a part of this thesis, it was made clear that there are significant 53 works and initiatives that happen to share learnings both within and between organizations and with industry to improve the organizational learning across the board. The BCOGC is actively improving and developing a compliance management system to promote business intelligence where learning from operator reports flows upward to a single accessible location. They are also developing a safety oversight management system that is related to environmental safety and will increase the information gathering and maintenance systems for the company. The CER is promoting better transparency through publishing terminal inspections, resource assessments on the Country’s needs vs capacity for gas resources, and incident response information/reports. Both agencies pointed to an increase in collaboration and diversifying research through the greater involvement of academic institutions and the international safety community. There is also a notable evolution in the intent to engage Indigenous communities on pipeline safety and management and further incorporation into emergency planning strategies. The BCOGC and the CER are currently jointly involved in a pilot Indigenous stewardship program that aims to engage Indigenous monitors to participate in pipeline inspections and to provide their unique perspective to pipeline development and safety in their territory. Members from both the CER and the BCOGC alluded to the willingness of other jurisdictions, including other provinces, to engage in regular, informal, information sharing where there may have been relevant learnings. Both organizations also engage with each other and others through the Western Regulators Forum, a group that includes the CER and BCOGC as well as regulators from Alberta and Saskatchewan. Its mandate is to facilitate the exchange of information and discussion of ideas with respect to the regulation of oil and gas activities in Western Canada and identify important areas for collaboration in research, program development, standards development, and other areas of mutual interest (NEB, 2018). The 54 cooperative learning outcomes from these engagements allows regulators to provide a clearer message on safety standards and expectations for industry, and thereby ensure that changes are made at an operation level. 55 Chapter 3: The evolving nature of pipelines, risk management and incident response in British Columbia 3.1 Introduction The second industrial revolution of the 19th century introduced the mass production of steel and readily available petro-chemicals into western markets for the first time. Through the end of that century and into the 20th century, new and growing oil companies pushed further and further into the remote areas of the world looking for viable resource deposits. Where these resources were found, they needed to be transported back to populated areas for processing and access to consumer markets. Pipelines have been a part of the British Columbian economy and environment for over 50 years. Over that time the conversation about the roles and responsibilities of industry leaders and government in respect to pipeline safety and environmental responsibility has evolved as technology has advanced, incidents have occurred, and public concern and awareness has changed. The responsibility and capacity for both industry and government to learn from pipeline incidents and translate that learning into progress has become tantamount in ongoing discussions about the role of pipelines in BC’s future. Chapter 2 of this Thesis laid the groundwork of the roles and responsibilities of the players in BCs pipeline industry. This chapter examines the evolution of risk perception in BC’s pipeline industry and looks at how responsible organizations learn from incidents over time and use that experience to change and improve their operations. 56 3.2 Methodology This chapter is founded on a literature review of factors relevant to industrial and regulatory learning from incidents. It explores the theories behind determining learning organizations and the existing challenges that exist to an industrial fields ability to adapt and evolve. Topics include how industries learn from incidents and the role organizational learning plays in changing corporate culture, as well as evolving perceptions of risk in the industry and how that is shaping the accident investigations that form the foundation for future learnings. Academic journals were searched using both databases accessible through the university as well as Google Scholar. Key search terms included: pipeline incident, industrial incident, organizational learning, industry learning, accident investigation, pipeline risk, industry risk, accident evaluation, accident assessment, risk, risk perception and risk evaluation. 3.3 Literature Review 3.3.1 Industrial learning from incidents Gas pipeline companies are increasingly having discussions framed around the risks surrounding incidents. Alongside, there is a reduced tolerance from governments and the public towards the consequence of an incident. These two priorities around the industry required an increased focus on the evolution and institutional learning that occurs after an incident occurs. How are the lessons from an event, incorporated into the corporate memory and how do they change the day-to-day operations of the pipeline moving forward? The traditional theory of incident-based learning is that when a thorough analysis is performed and lessons are formulated, this will lead to the prevention of incidents (Blanco et al., 2000). Learning from incidents should not only focus on preventing recurrence but also on improving overall safety within the organization and industry as well as on improving the learning from incidents process itself, 57 often referred to as ‘organizational learning’ (Drupsteen et. al., 2013). Organizations learn because they want to and/or they must. Organizational learning is a complicated subject. Researchers range in subject expertise from psychologists and behaviourists to corporate specialists and health and safety professionals, all of which have their own definition on how exactly organizational learning is defined and no two are exactly alike (Dodgson, 1993). All have a different perspective on both why lessons are or are not absorbed by a company and what the appropriate method to correct this is. Some researchers have argued that different disciplines perspectives on organizational learning create distinct research ontologies, making universal application of principles difficult (Easterby-Smith, 1997). Others such as Argote & Miron-Spektor (2011) have created extensive theoretical frameworks to analyze the current and emerging themes in organizational learning research. The most common theme across all disciplines in the field is knowledge transfer; how information is gathered from individuals and reshared across a company to maintain a constant positive evolution. The research for this Thesis has selected the framework presented by Garvin (2003) to evaluate institutional learning in the natural gas pipeline industry. Garvin’s approach represents a multi-disciplinary approach that emphasizes practical observations rather than a scholarly debate on the subject. While there are extensive and valuable models such as those created by Aragot & Miron-Spektor (2011), the nature of this study’s close association with industry incident reports and government technical reviews lent itself well to a model that prioritized practical and applicable methodologies. Five questions help determine if an organization can be considered a learning organization (Garvin, 2003): 58 (1) Does the organization have a defined learning agenda? There should be a clear understanding of what future avenues of learning will be and they should be pursued through a variety of means (2) Is the organization open to discordant information? Is the management of the organization open to being challenged on new ideas or concepts or is there a general discouragement of people stepping forward? (3) Does the organization avoid repeating the same mistakes? The lessons from past mistakes should be distilled into lessons that are shared internally through various methodologies. Accidents and near misses should be treated as learning opportunities rather than purely as causes for discipline. This may be particularly applicable to the natural gas pipeline industry and this body of work. (4) Does the Organization lose critical knowledge when key people leave? The knowledge of people with specialized skills or a lifetime of experience should be incorporated into the documentation and training of the organization, so it becomes common property. (5) Does the Organization act on what it knows? Future behaviour of the company/organization and its employees should reflect new learnings. Traditionally, resource industries such as oil and gas have struggled to incorporate a ‘learning culture’ into day-to-day operations. Entrenched workplace cultures that maintain strong divisions between ‘blue-collar’ and ‘white-collar’ workers have historically created difficulties in the transfer of knowledge from operational to management levels and back (Dymock, 2003). It may be that any time spent on workplace education can be seen as an additional burden on top of an already full workday or schedule. As well, tight timelines during the construction of new projects or busy schedules of time-sensitive work make setting aside time for multiple employees to debrief or incorporate new information particularly challenging. In order for learning to occur, 59 employees have to be given the time to absorb new information and perform additional new tasks. This means that previous tasks need to be done away with or modified to avoid overload. Unfortunately, it may be that the organization only understands how to add to an employee's required tasks (Garvin, 2003). There is also the extra financial burden of training and incorporating new technologies as well as likely a temporary reduction in productivity as re-training occurs. Equipment in the oil and gas industry leans towards being highly specialized, and therefore comes at a higher cost than may be the case for other industries. Investments are expected to last several years. All of this means that traditionally, in day-to-day operations, the traditional adage of “if it ain't broke, don’t fix it” is often applied, leading to a slow adoption of new technologies and advances (Bush, 2011). Organizations can also lose already existing institutional knowledge through the loss of the individuals as they leave the organization without the lessons previously learned being disseminated into corporate training (Kletz, 2003). Incidents represent a unique opportunity to fast forward institutional learning. Not only are there clear lessons to be learned from the causes and outcomes of the incident and the subsequent response, but as well, staff are typically re-tasked from their daily projects, daily inertia is disrupted, and they are brought together with employees or contractors that they would not typically work with. This creates a short-term environment that has the potential to foster significant learning if managed correctly. The biggest challenge is how to ensure any lessons learned are entrenched into a company's long-term memory, so the same incident never occurs again, at least not in the same way. Organizations often succeed at creating, acquiring, and interpreting knowledge but then often fail in applying, or translating that newly gained knowledge into future activities (Garvin, 2003). A study of the effectiveness of incident learning 60 based on the EU’s Major Accident Hazards Bureau accident database found that only one-third of cases showed learning on a broader scale than the immediate facility (Jacobsson et al., 2010). One of the primary drivers of learning from incidents is the accident investigation/analysis that happens after an event. Since the 1990s, there has been a push for organizations to focus on the management responsibilities for the worksite conditions and technical failures that lead to an event (Kontogiannis et al., 2000). This is reflected in the increased research into organizational learning at the time and the amendments to federal occupational health and safety laws after the Westray coal mine incident (Dodgson, 1993). In 1992 at Westray, Nova Scotia, a methane explosion killed 26 miners. The accident investigation for the accident determined negligence and abuse on the part of the mine owners was responsible for the death of 26 miners. The owners were criminally charged and several Ministry of Labour officials, including the minister, were dismissed (Brittle, 2012). The outcome of this incident altered the occupational health and safety landscape in Canada and added a new gravity to the importance of thorough accident investigations in the industry that attempted to ascertain, not only what happened at the time of the incident, but the ‘root causes’ that contributed right up to a managerial or even political level. Failures of organizational systems underpinning an industry have been proven to lead to latent failures such as maintenance problems, inadequate training, and other procedures that will eventually be the cause of an incident (Kontogiannis et al., 2000). The scale of an accident analysis should reflect the size and severity of the incident; however, the methodology and thoroughness can vary. Commonly, the investigation is conducted in-house by a designated and trained person or team. In Canadian pipeline incidents, larger federal regulators such as the Canada Energy Regulator defer to an independent government third party entity to conduct the investigation, i.e., the Transportation Safety Board. 61 Where human injury becomes a factor in BC, WorkSafeBC is likely to become involved. The jurisdiction of pipelines in BC is further covered in Chapter 2 of this thesis. Accident investigation of safety-critical infrastructure has become increasingly difficult and requires an investigation to acknowledge both a technical system with interrelated components and the dynamic responses to unanticipated events and human interactions (Kontogiannis et al., 2000). Modern accident investigations typically follow either a fault tree analysis (FTA) or sequentially timed events plotting (STEP) method to analyze the critical events, errors, and how the chain of events or failures played out. These methods allow investigators to follow a chain of events back in time in order to identify what the root causes of an event were, beyond the obvious mechanical failure or human error that occurred immediately before the event. Aside from assigning fault and liability, one of the primary outcomes of an accident investigation should be communication and learning from the incident, so that future ones can be prevented. However, these two concepts are often antagonistic, with the fear of liability causing a denial that impedes learning (Pidgeon & O’Leary, 2000). Modern workplace liabilities and WorkSafe laws may also cause company policies to put an emphasis on personal safety (e.g. falls or vehicle accidents) to the point that it overshadows process safety (e.g. equipment malfunction) and causes myopia for a major incident risk (Hopkins, 2008). A company's incident reporting system should be seen as the method the organization disseminates lessons learned throughout the company. In order for this to be effective, there has to be some sort of formal system in place that not only incorporates incident information but also collates all near-miss events that occur during work. There should also be a clear line drawn in organizational policy differentiating the acceptance of failure and a lack of accountability. If an employee makes a decision that was 62 based on the available data and sound logic, then the failure should represent a learning opportunity (Garvin, 2003). Whereas if it was an isolated poor decision, given the circumstance, then there will be consequences. Incident-reporting is often underutilized, only events that are identified as significant and require repair or medical intervention are reported (Sanne, 2008). Some issues around ‘significance’ is the result of jurisdictional requirements (Blair et al., 2017), while others are related to perceptions of risk and a workplace or regional ‘culture’ that is inclined to brush off issues in favour of being perceived as a diligent employee or team player (Mearns & Yule, 2009). These under-reported near misses have the potential to increase the likelihood of a significant incident occurring, as the warning signs may have been present, but were unknown to the relevant people. Often the potential consequences of incidents, caused in some part by human failure, are not understood by the people who caused them but could have provided a warning if reported and the behaviour or equipment issue was corrected (Blanco et. al., 1996). Despite the increase in detailed safety investigations and organizational comprehension of the necessity to learn from incidents, there are still repeat events. The safety literature reflects on the failure of organizations to successfully learn from incidents (Drupsteen & Guldenmund, 2014) including the underreporting of incidents (Blair et al., 2017; Sanne, 2008), weak root cause analysis (Jacobsson et al., 2009), or a breakdown on the political and organizational decision processes (Hobden et al., 2011). Surveys have shown that learning potential was especially lost at the reporting and the evaluating steps, and the latter was a critical step for the learning to learn process (Drupsteen et al., 2013). A study conducted by Hovden et. al., (2011) interviewed those involved in the response to serious incidents in the transportation industry to determine what, in their opinion, were the 63 most important criteria for organizational learning and what did or did not drive change in the industry. The results showed a strong support for independent, detailed accident investigations that are conducted by competent teams with the findings being made publicly available as soon as possible after the event. These factors increased the perceived reliability of the investigation both from those involved and increased the trust and confidence of the public at large. In BC, federally regulated pipeline incidents achieve most of the criteria outlined by Hovden et al., (2011); they are completed by trained independent auditors and findings are shared with the public at the conclusion of the investigation. For federal incidents, investigations are carried out by the Transportation Safety Board (TSB) on behalf of the Canada Energy Regulator (CER). The TSB operates as an independent agency whose mandate is to provide the public with the documented details and findings of incidents related to energy, transportation, and marine safety. Reports are publicly available on their website, they are easy to find, and written for a broad audience. The BC Oil and Gas Commission (BCOGC) which regulates pipelines under the provincial jurisdiction dispatches operations inspectors to a site for immediate investigation if it is deemed necessary by the designated Emergency Officer on duty (BCOGC Public Safety Report, 2011). The investigation reports are shared within the industry between regulators and companies, however, are not easily or readily available to the public. There was a Memorandum of Understanding between the former National Energy Board (NEB) which the new CER has maintained with the BCOGC where the province could request assistance from CER in respect to pipeline incident investigation (NEB, 2007). However, in the case of a federal incident, CER will always defer to the TSB. The participants in the study from Hovden et. al., (2011) also considered it important for there to be cooperation between the regulatory authorities and the company, with the former 64 making specific recommendations and subsequently following up to make sure the recommendations are followed. These recommendations should represent the summation of learning derived from both the investigation and the collective best practices of the industry based on previous experiences. The Canada Energy Regulator (CER) and the TSB follow up on recommendations, sometimes restricting operations of the pipeline until the required adjustments have been made. The BCOGC follows suit here, keeping in regular contact with operators and through work on joint technical committees that involve industry, academia, and regulators and work to inform technical standards groups such as the Canadian Safety Association. Organizational learning and transmitting the lessons learned through incident response and investigation are paramount to improving the resilience and overall safety of the industry. In reviewing the relevant literature, it can be determined that there are frameworks in place to support the aims of a learning organization and that modern iterations of industry guidance documents have greatly improved in promoting the values of a learning organization. 3.3.2 Institutional perception of risk and how it affects incident learning Risk, like learning, is a word that is often used in organizations without a clear understanding of the intent, context, or perceived value. The understanding of these concepts impacts the ability of organizations to incorporate and communicate lessons learned from previous experiences. Risk as an abstract concept is something that everyone is familiar with at some level. It is embedded in the calculations we perform every day. For example, the decision to go retrieve the mail without a coat; uncomfortable, but the risk of injury is low. This is a microscopic example of a risk assessment, which at its core is simply the likelihood of an occurrence multiplied by the severity of a negative outcome. The goal of risk assessment and analysis is to identify potential issues in advance so they can be avoided or managed. Risk 65 assessment, analysis and management is a vital component of most industries, and its perceived importance is only growing over time. In recent decades, the nature of risk management has been evolving. Increasing volumes of available data, the acknowledgement of the trans-disciplinary nature of issues and increasing tasks managing public and media perception have dramatically complicated the process (Smith & Fishbacher, 2009). This is particularly true of pipeline projects in BC which contend with both fierce public scrutiny and increasingly vigorous environmental regulations. 3.3.3 Risk analysis Risk analysis is relevant to every part of a pipeline project and its operations, and at every phase in the lifecycle of a pipeline. The analysis, therefore, is scalable to a project and can span from a handwritten matrix before starting a task to a detailed computer model based on fuzzy probability theory. At a high level, all risk analysis methods can be divided into two camps: quantitative and qualitative. Qualitative methods rely on experienced people to provide informed, and expertise based, albeit subjective assessments of the risk level of a task and the possible avenues of failure, combined with historical information to determine the risk of future events. They include approaches such as Analytic Hierarchy Process and Event Tree Analysis which rely on identifying the root cause of incidents (Han & Weng, 2011), often ranking the results using a predetermined scale. Quantitative analysis, sometimes called probabilistic analysis, is a formal and systematic approach to risk assessment that relies on modelling software to determine the numerical probability of events occurring and their possible outcomes (Smith & Simpson, 2020). Quantitative assessments are capable of incorporating a greater number of variables and provide a more robust assessment, however, are more time-consuming and costly to complete. Both methods have merit and certain methods may be more appropriate to specific 66 tasks than others. The study of these methods and attempts to invent new, more reliable systems of risk assessment are well applied in the oil and gas industry (Han & Weng, 2011; Jo & Ahn, 2005; Smith & Simpson, 2020; Bagheri et al., 2016; Jamshidi et al., 2013; Shahriar et al., 2012; Bilal et al., 2016; Lu et al., 2015; Ma et al., 2013). No matter what method of calculation is used, two issues remain difficult to navigate: variability and uncertainty. Variability refers to identifiable differences between individuals or components being analyzed, such as different pipeline manufacturing methods. Variability within a system cannot be mitigated through better measurement and suggests that a single strategy to contend with risks may not be sufficient (Thompson, 2002). Uncertainty meanwhile arises from the incomplete knowledge of all the variables that could affect a project. Uncertainty should always be acknowledged in risk analysis, and in some cases can be mitigated through the incorporation of more high quality data. Evolving technologies and increased computational power over the last few decades have increasingly taken advantage of larger data resources to reduce the uncertainty in risk analysis, leading to increasing preferential use of probabilistic (quantitative) risk assessment methods (Thompson, 2002). The risks categories that could be part of a pipeline incident can be many. There is a risk to the health and safety of workers, environmental risk, the risk of equipment damage, and the risk of interrupted service to clients. All of these are risks immediate to the incident occurring and are generally the subject of extensive study and concern from the engineering faction of a pipeline project. The managers and owners of the company have further risks to consider. One of the greatest risks to a pipeline operator, or an incentive for continued safety, is cost. The financial risk of a large incident can have both immediate and lasting implications. Due to the ‘polluters pay’ regulations in Canada, any costs incurred during the process of environmental 67 remediation after an incident are carried by the pipeline operator. The pipeline company may also be liable for private property damage, injury claims, or civil lawsuits. All of this is in addition to any fines or enforcement that are imposed by regulators. In Canada, there is no upward limit on the amount a company may be required to pay (NRCAN, 2020). This financial strain may be absorbed by a large multinational company with only minor disruption, but for smaller, (local regional) operators, these costs may cause considerable damage to the company's finances. There is also increased public will to hold the management of companies personally responsible for incidents that occur on their job sites due to a lack of due care, regardless of whether or not it is their habit to personally oversee such matters. In the 2013 case of Ontario (Ministry of Labour) v. New Mex Canada Inc. after a death at the job site, on top of extensive fines to the company, each director was sentenced to 25 days in jail. The jail sentences were subsequently overturned during the appeal process; however, the legal repercussions being directed at managers and CEOs is becoming more the norm as laws across the country are amended. Beyond the direct cost of an incident, there is also a broader implication. While studies have shown that there is not a large or lasting deterrence effect from the stock market for environmental accidents like there is in the field of transportation (Carpentier & Suret, 2015), there is an initial short-term drop in profit. What may be more damaging in the long run is the reputational damage to a company (Oberndorfer et al. (2013). A company with a problematic reputation, and poor safety record, may encounter more difficulty in future project bids, find lenders uneasy about past events, or come up against a government regulator bowing to public pressure to either deny an application or be extra vigilant in the review and permitting processes. 68 A good risk analysis program and management plan acknowledges risk tolerance. Risk tolerance is subjective at both a personal and institutional level, influenced by factors such as geography (Salas et al., 2020), familiarity, confidence in institutional control, unequal distribution of risks and benefits (Heath & O’Hair, 2010), and unequal distribution of resources. A larger company may have a higher risk tolerance to the financial strain brought on by a pipeline incident than a smaller operation with lower profit margins. A multi-national pipeline industry may also encounter different risk tolerances in the regulators it navigates in different nations. In Canada, as risk analysis has changed, so too has the risk tolerance of industry evolved over time, trending towards caution. Increased financial penalties, more robust health and safety legislation with the requisite enforcement and increased media attention have all played a part in reducing the risk tolerance of modern industry (Spence, D.B, 2011). The rise of social media has also contributed to the consequence of a significant incident. Of any industry in Canada today, the pipelines industry in particular, seems to be subject to vocal and often polarized public opinion. Any incident large enough to receive media attention becomes a rallying point for pipeline opposition and the numbers of protests and petitions gained through social media streams may be enough to sway political and public opinion against a project. One study (Smith & van Ierland, 2018) found that Twitter, in particular, is playing an increasingly influential role in shaping public perception of industries and industrial projects and that the discussion is rarely framed by scientific fact, but rather morality and conflict. The risk of a pipeline incident exacerbating this community conflict can have long-reaching consequences. 69 3.3.4 Accident investigation and reporting Quantitative risk analysis and studies of risk paradigms for pipelines rely on available data sets. These data sets are typically the product of regulatory agencies maintaining documentation from accident investigations. Because of this, modern accident investigation must contend with several challenges; there is a lack of integration on various institutional levels (global, regional, national, local) and between sectors, dealing with different interests held by stakeholders, organizational and methodological shortcomings (Roed-Larsen & Stoop, 2012). Without comparable investigative reports and data sets, it is difficult to conduct meaningful research into the causes and effects of incidents at different scales. Even something as fundamental as the definition of what is and what is not an incident, or the use of the word accident can be variable and change over time. Commonly the word “incident” refers to the combined set of occurrences of both accidents and near misses (Drupsteen, 2013). However, despite being considered best practice (Collins, 2010), not all companies will analyze or report a near miss. Other groups may use the words (incident/accident) to differentiate the scale of an occurrence. In certain industries, including the pipeline sector, the use of the term “accident” is gradually being phased out in favour of exclusively using “incident”. The reasoning behind this is that the use of “accident” implies an unavoidable ‘act of god’, rather than the breakdown or failure of controls that could be amended to avoid a future mishap. Incidents are an outcome of organizational failure causes that should have been addressed (Drupsteen, 2013). Or put another way, to refer to it as an accident is to deny responsibility. In analyzing US national pipeline databases, Silver-Evans et al (2014) found a dramatic change in incident reports after the definition of ‘incident’ was changed. Prior to the change, only events resulting in fires were 70 classified as ‘incidents’. These inconsistencies in reporting affect the outcome of risk assessments and create challenges for researchers, and industry representatives alike. In the BC pipeline landscape, the two bodies responsible for accident investigation (TSB & BCOGC) have different definitions of accident and incident. The Transportation Safety Board defines a pipeline accident as an event resulting directly from pipeline operation that results in: serious injury or death, a rupture; (i.e., an instantaneous release that immediately impacts the operation of a pipeline segment such that the pressure of the segment cannot be maintained), fire or explosion that could cause bodily or environmental harm, an unintended or uncontained release of a product that results in a significant adverse effect on people or the environment (TSB Statistical Summary, 2019). All other occurrences: damage to the pipeline (third-party, geotechnical, mechanical), gas releases, fire or ignition that affects pipeline operation but does not cause measurable damage, are classified as incidents. The TSB uses the more traditional convention of ‘accident’ and ‘incident’ to classify the scale of the event, including thresholds for size, number of injuries, or damage in dollars. Meanwhile, the BCOG refers to all events as incidents, rating them from minor, through to serious depending on the consequence or damage caused (BCOGC Incident Classification Matrix, 2019). But nowhere in the documentation on reporting requirements or standards is the word ‘accident’ used. This difference in reporting standards is an example of the challenges of institutional integration. 3.3.5 Risk Communication At a time when public interest, and scrutiny, of the pipeline industry in BC is arguably at an all-time high, the ability of regulators and industry to clearly communicate risk has never been more important. In recent decades, risk communication has increasingly emphasized the process of risk management rather than the content itself (Power, 2007). As the perception of risk and the 71 value of gains is entirely subjective and is influenced by a range of factors such as education, political ideology, and geographical distance from the project (Clarke et al., 2016), communication strategies cannot take a ‘one-size-fits-all’ strategy. Another challenging factor for risk communication is the level of public trust in the science being conducted by regulators (Pollack, 1995), increasingly challenged by online media dissemination of information. This is a rapidly evolving component of risk management for industry and regulators and pipeline companies have been criticized for not fully utilizing social media to increase dialogue with stakeholders (Pizzi et al., 2020). The consequences of mismanaging the risk communication for a project can be serious and lasting. There are several recent examples in Canada alone of communication failures from the oil and gas industry. Montpetit et al. (2016) suggest that the overwhelmingly negative press associated with shale gas development in Quebec was enough to play a role in disrupting pro-gas advocacy, leading to a government policy turnaround and a moratorium put in place. In BC during the lead-up to Enbridge submitting their application for the development of the Kitimat Terminal, an animated informative PR video intended to sway public opinion on the project was released. In the video, the Douglas Channel which would have to be navigated by tankers to access the terminal was depicted inaccurately, removing approximately 1,000 square kilometres of islands (Lavoie, 2012). There was a major backlash against the video with the perception being that at worst Enbridge was intentionally misleading the public regarding the risks surrounding the project, and at best it was an unintentional but misguided oversimplification of the shipping route. 72 3.3.6 Conclusion and challenges to risk management for the pipeline industry Risk analysis, management, and communication is an evolving facet of the natural gas pipeline industry in BC. It is a complicated, multidisciplinary field that is challenged each time an incident occurs. It also has the potential to serve as a unifying agent; an aspect of pipeline projects that operators, owners, and regulators alike must contend with. While rapidly developing technology, computing power and data storage increase the data available for robust risk analysis, challenges remain in inconsistent reporting across jurisdictions. Data sets coupled with cohesive incident investigations and reporting will improve the risk management strategies for the industry as a whole. The further use of tailored and modernized communication strategies for risk communication will also improve stakeholder engagement on large projects. A unified understanding of risk and how our definitions and perceptions shape both incident investigations and impact assessments will improve our ability to institute risk analysis into industry and regulators organizational learning cultures. While risks in the industry cannot be avoided entirely, the continued study and development of risk management programs improve the safety and accountability of the industry. 73 Chapter 4: A Chronology of Pipeline Events in BC 4.1 Introduction No system, no matter how carefully designed, is infallible. Incidents or failures of materials, systems and training have happened many times in the natural gas pipeline industry, including in the province of British Columbia. Where these incidents do occur, there is an opportunity to examine failure, learn, and apply these lessons to ensure an incident never occurs again in the exact same way. The following chapter explores pipeline incidents in BC in a chronological manner, exploring the causes, investigations, and the results of several incidents. 4.2 Methodology The primary method of research for this chapter of the thesis is case study based. Five distinct incidents of natural gas pipeline incidents over an extended period in British Columbia were examined. The five case studies (Monias Pipeline, Zymoetz river incident, Encana pipeline explosions, Nig Creek pipeline incident and the Westcoast pipeline incident near Prince George) were selected to demonstrate both different and similar causes of incidents that are representative of significant risks to pipelines in the province, and how the accident reporting and adaptations have changed over time. The case studies were chosen to examine the results of learning and adapting the industry from incidents as they represent an empirical method that allows the researcher to investigate a contemporary phenomenon in depth and within a real-world context. Case studies were selected based on the breadth of causal factors leading to failure as well as for scale and available information. The scope of the case studies was limited to natural gas incidents within the province of British Columbia to maintain the limits of what was achievable in a master’s thesis. While other approaches may provide more quantitative detail, it can run the risk of removing the subject from its larger context, which in the case of pipeline incidents can 74 represent an overly narrow focus on only one cause of incidents, ignoring others; or focusing on engineering cause alone, while possibly removing the effect of human error from consideration. The nature of this study involved multiple sources of evidence, some quantitative, but largely qualitative that lends itself to the triangulating study fashion of a case study methodology. Context for the case studies was based on review of existing academic research on pipeline risks, incidents, and engineering studies from BC, Canada, and around the world. The descriptive walkthrough of the incidents was primarily taken from government accident investigations where available and supported by existing literature and other government documentation. To support conclusions drawn on the applied learning from both industry and government over time, information gathered from focus groups with key government regulators was included. The information provided, knowledge, and experience provided during the focus groups delivered additional important insight into the communication between government and industry, as well as the evolving priorities and standards that natural gas companies must meet in terms of safety and response readiness. The questions that were asked in the focus groups are available in Appendix A. To further illustrate the longitudinal nature of the study area, a timeline of natural gas pipeline events in the province and events that had significance for the province has been included. 4.3 Pipeline event timeline The following section outlines important events in the history of natural gas pipelines in British Columbia. These events, including incidents as well as notable developments of legislation and policy that govern the safety of the industry, help outline the evolution of the industry in the province. The succession of events also illustrates the impact pipeline incidents, along with evolving risk tolerances and research advances, have had on government and industry 75 policy. Events were selected based on the relative scale of the incident, or the impact changes to policy had on the industry as a whole. • 1947: The first successful gas well was drilled in the Peace River area of British Columbia o The first oil and gas tenure was issued, allowing a permit holder the right to conduct geological work. • 1955: Westcoast Transmission Company Ltd begins construction on a pipeline from Taylor BC to the United States. • 1956: The Petroleum and Natural Gas Branch was established • 1957: TransCanada Pipelines Ltd constructs a natural gas pipeline across Canada. o Westcoast Transmission Company Ltd transports natural gas from NE BC to the United States. • 1959: The National Energy Board (NEB) was created and became responsible for regulating oil, gas, and electricity exports as well as federally mandated pipelines. • 1963: Canadian Standards Association published the CSAZ 183/184 standard for pipelines which outlines the best practice standards for the creation, testing, maintenance, and operation of pipelines in Canada. The standard was later updated to the modern CSA Z662 in 1994 which is updated every four years and is currently on its 19th iteration. • 1991 - 92: TransCanada experienced its fourth and fifth pipeline ruptures caused by stress-corrosion cracking (SCC). • 1993: An inquiry into stress-corrosion cracking was launched by the National Energy Board (NEB) in response to TransCanada’s pipeline ruptures. A total of 47 parties participated in the inquiry and a report was issued. The report concluded that SCC was 76 not a significant problem in Canada, and where it did exist it was being suitably managed (NEB, 1996). Any arbitrary conditions that could be placed on operators were deemed unduly arduous for natural gas producers and consumers. o The Canadian Energy Pipeline Association (CEPA) is formed, funded by and representing industry stakeholders. • 1994: CSA Pipeline Safety Standard Z662 is released, outlining best industry standards for safe pipeline creation, installation, maintenance and operation. Both federal and provincial oil and gas agencies adopt the CSA standard in their requirements for industry. • 1995: Two more SCC related ruptures occur on TransCanada pipelines, one in Northern Ontario and one in Manitoba. In response the NEB launched a wide-ranging public inquiry into stress corrosion cracking, incorporating industry, consultants, academics, public, and regulatory agency knowledge on the subject. • 1996: The report of the public inquiry from the National Energy Board is released, detailing all causes and aggravating factors for SCC in Canadian pipelines that could be identified. • 1997: The Canadian Energy Pipeline Association (CEPA), a private industry group, publishes the first ‘Stress Corrosion Cracking - Recommended Practices’ document with detailed guidelines for industry on the identification, mitigation, and management of low or near-neutral pH SCC. It creates a template for pipeline companies to create their own SCC Management plans. o The Monias Pipeline near Fort St. John ruptured. Failure was determined to be caused by geotechnical failure. 77 • 1998: The BC Oil and Gas Commission (BCOGC) is created. The Commission was intended to regulate the industry and increase efficiency for permit applicants by creating a “one-window” process. The BCOGC was granted permission to manage specified enactments of the Land Act, Water Act, Forest Act, Environmental Management Act, and Heritage Conservation Act as they relate to Oil, Gas, and Pipeline development. • 2000: A natural gas pipeline operated by Westcoast Energy Inc ruptured near the Zopkios rest stop on the Coquihalla Highway, closing the highway for 3 ½ hrs. • 2002: Pipeline near Terrace BC is severed by a significant landslide (Zymoetz) • 2003: CSA Z662 Safety Standard update is released. Significant amendments include requirements concerning the selection of coatings and the effect of pipeline operating temperatures on the environment, requirements regarding protective coatings, requirements for pressure testing and weld inspection, and a guide of appropriate testing methods for coating properties. • 2007: CEPA Releases the second edition of the SCC - Recommended Practices document. Updates include the addition of guidance for post SCC incident investigations and returning a pipeline to service, more detailed severity assessments. o CSA Pipeline safety standard Z662 is updated. Significant amendments include: new requirements for safety and loss management systems, integrity management programs, and risk assessments to improve community safety, and increase stakeholder awareness of safety issues, as well as more training requirements for personnel applying field coatings. • 2009: EnCana sour gas pipeline adjacent to a well in Pouce Coupe failed, releasing 30,000 cubic metres of sour natural gas into the atmosphere. 78 • 2010: The Oil and Gas Activities Act (OGAA) is proclaimed, significantly changing the legal regime for oil and gas activities in British Columbia. The Act attempted to simplify the provincial oil and gas framework by consolidating requirements that were under other Acts that were subsequently repealed (Oil and Gas Commission Act, the Pipeline Act, as well as some provisions from the Petroleum and Natural Gas Act). Importantly the OGAA included expanded consultation and notification requirements related to First Nations. The OGAA also provided the BCOGC with expanded compliance and enforcement tools. o The National Energy Board and the Environmental Assessment Office of British Columbia enter an equivalency agreement; where environmental certificates for projects issued by one agency can stand for the other. • 2011: CSA Pipeline Safety standard Z662 is updated. Significant amendments include: a revised annex of “Guidelines for Pipeline System Integrity Management Programs”, updated requirements reflecting newer material technologies like reinforced composite, and an increased focus on prevention and control measures, particularly the potential for uncontrolled fires • 2012: Nig Creek pipeline (Westcoast Energy Inc) ignites, also igniting adjacent Bonavista pipeline. 962,000 m3 of gas was released and 1.6 hectares of the surrounding land was burned. o Westcoast Energy Inc (working as Spectra Energy Transmission) was servicing valves at a Compressor station for annual maintenance 160 km NW of Fort St John when a sweet natural gas leak ignited, injuring one employee. 79 • 2014: CSA Standard Z246.2 is released for the first time. The standard establishes criteria for the emergency preparedness and response for the petroleum and natural gas industry systems. It is adopted and referenced by agencies in addition to Z662 and used as a guideline by industry. • 2015: CEPA releases the third edition of the SCC - Recommended Practices document. Updates include a new section on SCC Characteristic and Trends, recommended hydrostatic test procedures and methodology for estimating retest intervals, comparisons between detection technologies, and a comparison of methods used for predicting failure pressures. o CSZ Pipeline Safety Standard Z662 is updated, significant amendments include: updated requirements for safety and loss management systems, integrity management programs and engineering risk assessment processes, new requirements for training and certification of field-applied coating applicators, increased requirements for abandonment of pipelines and updated requirements for leak detection. o Bill 23 makes changes to the Oil and Gas Activities Act. • 2016: Federal Pipeline Safety Act comes into effect. The act enshrined the polluter-pays principle into law and clarified the inspection and audit authority of the Canada Energy Regulator (CER). It also ensures companies remain responsible for abandoned pipelines. • 2018: An explosion occurs on a Westcoast Energy Inc pipeline near Prince George, releasing 140 million standard cubic feet of natural gas and causing natural gas supply shortages in the area. 80 • 2019: Canadian Energy Regulator Act comes into effect. The CER takes over from the NEB. The act becomes the legal framework for the safe design, construction, operation, and abandonment of federally regulated pipelines. o The new Federal Impact Assessment Act is proclaimed, becoming the sole agency responsible for the management and coordination of impact assessments for federally regulated projects. o The new Provincial Environmental Assessment Act comes into force, bringing significant new requirements for notifications, engagement, and public involvement on industrial and resource projects. o CSZ Pipeline Safety Standard Z662 is updated, significant amendments include: re-written section that outlines design limits to improve safety including segmentation which was made mandatory, as well as population density assessments and consideration of the environmental effects of all low vapour pressure liquid pipelines. There were also increased inspection and testing requirements. 4.4 Pipeline incident case studies Case studies are organized in the following section from oldest to most recent. Each case study includes a location map of where the incident occurs, some broader context relevant to the cause of failure and research on the subject, a summary of the event, a summary of the subsequent investigation and findings and an analysis of the impact on the broader pipeline industry in British Columbia. 81 4.4.1 Case Studies Involving Geohazards: Monias & Zymoetz pipelines Aside from corrosion, metallurgical issues, and third-party interference, the effect of natural hazards or geo-hazards can present serious risks to gas pipeline integrity, and indeed have been the cause of significant incidents and accidents. Both within Canada and abroad the interaction/intersection of natural hazards and pipelines have caused destruction (Girgin & Krausmann, 2016). An earthquake in Ecuador in 1987 caused a massive debris flow that destroyed over 40 km of oil pipeline and caused 1000,000 bbl of oil to spill. In 1994 in Texas flooding in 1994 led to the rupture of several pipelines. Hurricanes in the Gulf of Mexico have previously damaged onshore pipelines with strong winds and storm surges (Santella et al., 2010). The types of hazards that can affect pipelines include any sort of ground movement like avalanches, debris flows, or rock falls, as well as tectonic activity, flooding, meteorological events, and erosion of the ground around the pipeline. Movement of the earth surrounding a buried pipeline places a lateral stress on the metal and can induce a rupture. Other factors and conditions compound these issues such as northern climates creating additional hazards from the increased freeze/thaw cycles and impacts of glaciation (Tart, 2008). Natural hazards present a risk that requires planning and mitigation strategies to be implemented at every stage of a pipeline's life cycle; from the initial route planning to throughout its operational lifespan. The expected life of a pipeline can extend beyond 50 years, but the risks from these natural hazards are not static and will inevitably evolve over time, and in many locales may also be exacerbated by climate change. Climate change has been linked to increases in the power of meteorological events (Knutson et al., 2010; Bengtsson et al., 2006; Jentsch et al., 2007), more frequent forest fires (Flannigan et al., 2000; Flannigan et al.,2009; Wotton et al., 82 2010), and flooding (Otto et al., 2018; Burn & Whitfield, 2016; Huber & Gulledge, 2011). Climate change may also contribute to changes in debris flows in mountainous areas (Charle et al., 2011; Jakob & Friele, 2010; Jakob & Lambert, 2009; Huggel et al., 2011). Such events have the capacity to damage pipelines and contribute to or cause incidents. Pipelines traversing British Columbia cover a challenging landscape. The province is known for its high mountains, deep river valleys, and dense forestation. BC has a diverse topography, and this poses unique challenges for operators of many types of linear facility. This, in combination with the potential for seismic activity, presents a difficulty for pipeline planners and operators by increasing the likelihood of incidents caused by natural hazards. Pipeline incident data from EU and the US databases rarely cites natural hazards as a cause for a pipeline failure; in both jurisdictions it is listed as a cause in less than 10% of cases (Porter et al., 2004). In Canada the numbers are slightly higher at 12.5% based on CER data from 2008 to now (CER, 2021). Some analysis has suggested that geohazards are broadly underestimated in pipeline failure cause assessments and they often result in significantly more damage and cost than other types of failures (Porter et al., 2004; Girgin & Kaussmen, 2016). In many parts of Canada, slope failure can occur at slopes as low as 3 degrees in loose weak clay shales, which makes it unlikely they were identified as landslides and were instead recorded in pipeline databases as failures to design or other conditions (Porter et al., 2016). The statistics for Canada federally, also may not reflect the British Columbian landscape (Belvederesi et al., 2017). Porter et al. (2014) reported incidents that occurred along pipelines is western North America and found that while geohazards occurred on average every 5 km across the prairies, that distance shortened to 2.5 km in the mountains. While this all may point to a higher incidence rate in Canada from natural hazards, it should be noted that Canada also has statistically fewer 3rd-party interference issues 83 that lead to releases than other jurisdictions, likely because pipelines often run through sparsely inhabited areas. This relative lack of human-pipeline interaction means 3rd-party interference consists of a smaller percentage of total incident causes in Canada than in other jurisdictions. This is important for planning routes, preparing response plans, and ensuring that response resources are strategically located. Because BC’s landscape presents challenges to pipeline construction and operation, and poses specific geological and geotechnical qualities, ground movement is common but also often hard to predict. One of the primary causes of geohazard type incidents in mountainous areas, like parts of BC, is from landslides. Landslides are a mass down-slope movement of soil or rock that are triggered through erosion, undercutting, water table conditions or seismic activity. Between 1973 and 2006, at least 38 rapid landslides carrying a load of more than 0.5 m3 with run outs of over 1 km were recorded in northern BC (Geertsema et al., 2006). Landslides of this scale have the capacity to severely damage even buried pipelines. Lee and Charman (2005) identified five main failure modes for buried pipelines subject to geohazards like landslides: 1. Lateral displacement, where the slide material exerts a lateral force on the pipeline to the point of failure from tension rupture; 2. Spanning, where failure results from the erosion of the underlying support material for the pipeline along a significant span; 3. Exposure and impact, where a pipeline is exposed and made vulnerable to subsequent falling material like boulders; 4. Loading, where the weight of the slide material burying a pipeline compromises the integrity, and; 84 5. the reactivation of pre-existing features, where there is a cumulative effect of previous slides and current ones. Such events may not have an isolated effect on a pipeline. Natural hazards affecting pipelines can contribute to other means of pipe degradation such as increasing the potential for corrosion and disbondment (Porter et al., 2004). Since the late 1990s in Canada, most pipeline companies have adopted some sort of proactive risk management practices (Savigny, 2005). Both in the planning phase and operational phase of a pipeline's life-cycle, operators work to manage the risks of a geohazard caused incident. Risk tolerance, both by governments and the residents of BC can be quite variable. Mostly, individuals have a much lower tolerance of risk from hazardous natural events, including landslides, than from any activities they voluntarily undertake, such as driving a car (Geertsema & Clague, 2011), so they generally have very high expectations of the efforts a company should be taking to reduce risk. There is also less tolerance for risk where the consequences are greater such as the risk of a pipeline rupture versus the risk of a forest road being washed out by a flood. As the seriousness of the consequences increases, risk tolerance is reduced. Increasingly pipeline companies in Canada are turning to more risk-based design, utilizing qualitative risk matrices and semi-quantitative data to support design decisions (Porter et al., 2004). The most traditional methods of identifying geotechnical hazards during the route selection process is to rely on expert assessment of geological mapping, aerial photography, or satellite imagery, followed up by field reconnaissance to ‘ground truth’ the location of problematic features more accurately (Nyman et al., 2008). Preliminary route appraisal stages of a project, the identification of a ~10km wide corridor that seems feasible, are based primarily on desk study by specialists in pipeline construction, hydraulics, operations, and terrain analysis 85 (Porter et al., 2014). Current trends in geohazard monitoring for pipelines focus on slope movements with the increasing use of satellite sensing and monitoring systems in remote areas capable of transmitting real-time information (Sweeney, 2017). There have been recent advances in these technologies. Singhroy et al. (2018) found that InSAR time-series deformation when combined with other geotechnical, hydrotechnical, and climatic information could be used to develop an early warning system to prevent pipeline ruptures in difficult mountainous terrains. In general, most practitioners have deemed the best practice is the combination of any and all of these resources as they are available (Newton et al., 2019). While a study conducted largely remotely, relying on the aid of technologies such as Lidar, satellite imagery or helicopter surveys, may seem insufficient, conducting further analysis of potential routes can be challenging. In some parts of western Canada, the permitting process for permission to conduct subsurface investigations can take six months or more (Porter et al., 2014). In order to not disrupt a project's timelines, permit applications (including environmental assessments) may be submitted when the routing specifics, exact locations, and even related baseline conditions, might not always be known. Developing such information is both costly and time consuming, but so is dealing with challenges after the fact. Uncertainties can cause disruptions, scheduling delays, and affect public confidence. In some cases, the geotechnical investigation activities to support mitigation measures might be conducted during the construction phase rather than ahead of time (Porter et al., 2014). Subsurface analysis of the sites is much easier to accomplish when the area has already been cleared, and snow avalanche hazard management is easier to study with ready access. Uncertainties, or gaps, about the geotechnical information along pipeline routes are common. For example, it is not unusual for the trench design for a pipeline to be based on widely spaced test pits (Nyman et al., 2008). But sampling 86 techniques, modelling, and other predictive approaches can be effective and provide reasonably reliable information. One of the primary challenges surrounding planning for landslide geohazards is the nature of landslides themselves. Despite the existence of many models, a precise method of prediction or estimation of displacement volumes does not currently exist (Baum et al., 2008). The irregular nature of most slide material in mountainous areas, including variable sediment sizes and vegetation being incorporated into the debris flow, make it difficult to model. Any risk assessments conducted by the pipeline operators need to incorporate this uncertainty into their planning. The type of uncertainty prevalent in the quantitative risk assessment of geohazards necessitates the incorporation of fuzzy data analysis (Girgin & Krausmann, 2013) in models attempting to rationalize the risk of an event occurring (Badida et al., 2019). There is also considerable uncertainty surrounding the potential of seismic events and how they might trigger other hazards such as landslides or avalanches. Avalanches themselves also represent a variable and difficult to predict risk as the threat they represent changes from year to year. The distance that pipelines can span makes it impossible to consider every geohazard and stream crossing or valley a pipeline route spans independently. While the risk of an incident may be reduced overall, the project cost associated with investigating every potential slide path makes it infeasible. Instead pipeline planners and operators increasingly rely on aggregate risk identification and management programs to manage smaller potential geohazards. In Canada, specialists have been working to improve these risk assessments from a geotechnical perspective. Researchers such as Savigny et al. (2002) have created natural hazard risk management programs that meet Canadian legal requirements and CSA guidelines for ‘hazard identification’ that are intended to be reproducible by companies and have been used to study the hydrotechnical 87 hazards of pipelines in the interior of BC. Areas that are determined to be a much higher risk will still require more costly approaches with specialist input (Sweeney, 2017). The primary method to mitigate geohazard caused incidents is through careful route planning to avoid areas of increased likelihood of ground movement. In general, it’s unlikely to be feasible financially or logistically to use engineering methods to stabilize large landslide areas (Nyman et al., 2008). However, avoidance becomes difficult for planners and operators in Canada and particularly in BC where pipelines are transiting through complicated geomorphological terrain where geotechnical information and access is quite limited. Spatial avoidance of the hazard must be considered both in vertical and horizontal dimensions and in some cases the area of risk may be a significant distance from the pipeline's location. In some circumstances an avalanche or rockslide can travel several kilometers from its point of origin. When there is no feasible way to route around a geohazard, planners and operators must turn to engineering methods of mitigating pipeline damage. A common strategy is to bury or elevate the pipeline structure to remove it from the path of a slide or avalanche. To be effective, the pipeline must be buried deep enough or elevated high enough to escape damage, with burial only being useful in the runout zones of debris flows or avalanches (Geertsema & Clague, 2011). Engineering designs to mitigate the effect of a landslide on a pipeline need to be supported by in depth investigations of the surface and subsurface materials and mechanisms of failure. This level of investigation is often beyond the scope of routine pipeline activity and the results do not offer any guarantee of success (Nyman et al., 2008). Where slide paths are unavoidable some engineering tactics to reduce the pipelines, vulnerability include adapting it’s orientation so it does not run traverse to the slide path or using shorter lengths of pipe (Ferris et al., 2016). Other proactive measures that operators can implement once the pipeline is in place involve ensuring 88 that the surrounding infrastructure, such as riprap replacement and erosion control, are well maintained (Newton et al., 2019) Pipelines that cross seismically active regions require consideration. Pipelines crossing fault zones must be capable of deforming longitudinally and flex to accommodate ground surface movement (Nyman et al., 2018). For the design to be effective, there has to be a reasonable understanding of the nature of the fault; location, orientation, slip characteristics and zone of disturbance must be identified to accurately calculate the amount of ground displacement that may occur (Nyman et al., 2018). Ideally, fault displacement predictions are based on historical data or site-specific studies, however as with other geohazards, there is often limited data available for these areas forcing planners to rely on risk assessments and best judgment. Engineering mitigation tactics for fault crossings include the appropriate selection of crossing angle, trench configuration and backfill, burial depth, and pipe wall thickness (Nyman et al., 2008). 89 4.4.2 Monias Pipeline Rupture 1997 Figure 4.1. Location map of the Monias pipeline incident The following is a summary of the incident from the Transportation Safety Board (TSB) Pipeline Investigation Report (P97H0024). The Event At 7:55 AM on the 30th of April, 1997, the Fort St. John Gas Control received a call from the local fire department, which had been in turn called by a landowner to notify them of a fire along the pipeline route owned by Westcoast Energy Inc. This phone call coincided with alarms sounding on the Supervisory Control and Data Acquisition (SCADA) system that showed 90 the Monias receiving line was losing pressure and a valve was closing. Within 3 minutes, the local police had also been called by a landowner. Police were able to set up a roadblock preventing access to the site until Westcoast personnel were able to arrive on site. Immediately after the rupture, Fort St. John Gas control requested the shutdown of all gas production feeding into the pipeline. The slope that ran beneath a section of the pipeline had slid at least 7 metres laterally, causing the pipeline to buckle and split along a proximal longitudinal weld. At the time of this incident there was no capacity to close production or to shut off valves remotely, a Westcoast crew was dispatched by helicopter to shut the valves that would isolate the production facilities from further supplying gas to the ruptured line. The dispatched crew continued up the line to close two other access points, one a simple block valve at the booster station, and the other another tie-in valve in order to further isolate the line. Area The ‘Milepost 20’ location along the Monias pipeline falls near old Fort St. John in the northeastern region of BC, in the Peace River Regional District. The region is relatively flat by BC standards, set within the Alberta plateau at 690 m asl and is largely characterized by boreal white and black spruce forests. There are several notable rivers in the area, with the most significant being the Peace River at 1,923 km long that stretches from Rocky Mountains in BC before joining the Athabasca River in northern Alberta. The substrate of the region is typified by quaternary sediments that are prone to translational landslides (Miller et al., 2018; Miller & Cruden, 2002;). The region is the most prolific area of BCs natural gas development because of the substantial conventional and non-conventional, or ‘tight’, shale gas plays that exist beneath the region. The pipeline rupture occurred just south of the town of Fort St John, the largest population in the region with a population of under 20,000. 91 History The Monias pipeline line was built in 1978 by Czar Resources and followed the route of an existing line; it crosses the Peace river near the Old Fort St. John area then turns first west then north east to accommodate the slope of the valley. The section of the pipeline in question was run over pre-existing landslide terrain. Since Westcoast Energy Inc acquired the line in 1985, they had instituted geotechnical monitoring programs that consisted of inspections such as annual aerial patrols, aerial patrols after heavy rainfall events and ground inspections after recorded ground movement events. Remediation measures such as surface grading to control water infiltration, filling tension cracks with clay and using skid mounts where necessary were used as required. In years leading up to the event, there had been slide activity in the area, but a regional geotechnical report had not identified the Monias Pipeline route as a spot of particular concern. There had also been significant rain and nearly record breaking snow levels that spring, conditions which prompted Westcoast Energy Inc to patrol the pipeline, looking for evidence of ground movement, earlier than scheduled. An examination using an intelligent pig had also not identified any metallurgical concerns. Analysis The TSB determined that the abnormally high-water levels over multiple years had re-activated a slide block that was a part of a larger landslide complex in the area. The sudden movement of the soil stressed the pipeline beyond its design constraints, allowing it to buckle and ultimately split open. This incident was not caused by any metallurgical flaws and was beyond the scope of the existing monitoring program to predict. The TSB did suggest that, as the tie-in valves needed to be manually operated, it would be prudent to have more of them near settled areas to expedite the shut off process. 92 After the incident investigation, Westcoast Energy Inc. took several actions to prevent a similar incident from occurring again. Additional shut off valves were installed to speed up the manual shut down process and limit the plume size in the Old Fort St. John area. The geotechnical monitoring system was strengthened by the addition of more monitoring instrumentation and by increased frequency of aerial surveys. The company identified a need to limit the plume size caused by an incident in geotechnically hazardous areas of their sour gas system in proximity to populated areas, indicating that there would be further study into the issue. It is unknown from this research whether direct action was made by Westcoast Energy inc on this issue, however plume dispersion or modelling has become a mandatory part of the Emergency Management Program for federally managed pipelines in Canada (CER, 2016). 93 4.4.3 Zymoetz Creek Incident Figure 4.2. Location of the Zymoetz Creek pipeline incident. The Area The incident occurred near the Zyometz River, proximal to where the Zyometz joins the Skeena River, outside of Terrace BC. The region is characterized by the Coast Mountains of Western British Columbia, a range that extends from the south of the province, north through to the Alaska Panhandle. The mountain range is considered relatively young geologically and is still an area of active seismic and mass wasting events. The rivers cutting through the area, particularly the Skeena River have carved terraces through glacial substrate deposited during the 94 quaternary period. The region is part of the coastal-interior rainforest, with a humid climate tempered by the proximity to the Pacific Ocean. The town of Terrace, which is the most substantial community near to the site of the incident, is home to over 13,000 people which makes it one of the larger population centres in Northern BC. The town's primary industry has traditionally been forestry, however in recent years that has been supplemented by LNG projects as well as Tourism. The Incident At 1:30 AM on the 8th of June, 2002, a rock avalanche and debris flow caused a natural gas incident near Terrace, BC. In a steep cirque basin at 1390 m, a rock avalanche initiated, sending 1.4 million m3 of rock 600 m down into the cirque basin where it transitioned into a debris flow (Porter, 2004). The debris flow flowed through a narrow, 300 m long canyon before reaching and destroying a natural gas pipeline and spreading further into the Zymoetz River (Copper River) floodplain, damming up a lake and forming a large fan (Porter, 2004). In total the debris flow travelled 4.5 km from the top of the avalanche to the furthest extent in the valley (Boultbee et al., 2006). Water backed up the floodplain 1.5 km, damned from the influx of sediment, before it was overtopped ~45 minutes later (Scwab et al., 2003). Plausible triggers of the slide were investigated and it was determined that it was likely a result of long-term degradation of the tectonically altered rock mass, possibly exacerbated by the influence of freeze-thaw processes and water reducing shear strength over time (Geerstema et al., 2006). The majority of the debris travelled the entire 4.6 km to the river, exhibiting surprising mobility (Boultbee et al., 2006) and scoured to a depth of more than 5 m (Geertsema & Clague, 2011). 95 The section that was ruptured is part of a 587 km long ‘Western Transmission’ or NPS10 gas pipeline that was constructed in 1968. Available data including BCOGC incident data, technical papers, and local news reports indicate that at least six confirmed failures from geohazards have occurred between 1991 and 2013 (Porter et al., 2016). The destruction of the line cut off Terrace residents natural gas supply temporarily, however by June 12, PNG had a temporary line in place on top of the bedrock canyon to continue service. PNG followed emergency plans as outlined in their Emergency Management Plans, shutting off flow from up the line and contacting the relevant authorities. Conclusion Pipeline routing in British Columbia is without a doubt, challenging. Between 1999 and 2007 Geertsema & Clague (2011) studied three incidents where a landslide in BC travelled more than 1 km to reach (and damage) a pipeline. They also reviewed a pipeline that ruptured after the clays beneath it failed in a river valley near Prince Rupert. Given the multi-decadal operational life of pipelines and the serious potential consequences of ruptures, pipeline companies need to make routing studies and the identification of potential landslides a priority. The region and causes of the Zymoetz slide have come under more considerable scrutiny in the last few years as the planned routing of the Northern Gateway Enbridge Pipeline route ran for a portion along the Zymoetz River. The Zymoetz incident was used during the Joint Panel Review (National Energy Board, 2012) by local NGO leaders to express disquietude over the planned route. The route of the planned Looping Project by Pacific Northern Gas also runs along the Zymoetz in some of the same area as the previous line (Pacific Northern Gas, 2013). However, the geotechnical hazards of the area are being considered in routing decisions. As a result of geotechnical concerns raised by consultants in the “Telkwa Pass” section of the proposed looping project, PNG concluded that 96 it was necessary to avoid the area and reroute the project to a more southern alignment through the coast mountains (PNG, 2006). This project is still undergoing the provincial environmental assessment process and applied to be transferred over to the New Environmental Assessment Act (2018) in April of 2020 (BCEAO, 2020). Changing climates have increased the intensity of rainfall events and flooding in the area, which when combined with the geological faulting (Boultbee et al., 2006) may be increasing the rate of local landslides (Geertsema & Clague, 2011), which affects both existing and any future pipelines in the area. In 2018, Pacific Northern Gas completed a $6 million project to repair and move a section of the natural gas pipeline running along the Zymoetz river which was damaged by heavy rains and flooding in 2017 (Link, 2018). The line was moved 840 metres to be above the estimated 200-year flood plain level for the valley. PNG themselves have acknowledged the increase in challenging geotechnical hazards, which when combined with an aging pipeline infrastructure equals an increasingly risky operation. The geohazards identified on the western-most part of the pipeline recently, exacerbate by the accepted design and construction specifics of 1968 have resulted in a “higher risk of damage and failure, complexity of maintenance….and resultant less than desirable conditions'' that have prompted PNG to submit a proposal to the BC Utilities Commision for a project for geotechnical mitigation (PNG, 2020). The company admits there was a period of approximately 20 years where some maintenance and integrity management was deferred in order to maintain financial integrity (PNG, 2020). There is a need to continue studying the risk of geotechnical hazards in the area to support mitigation measures. Debris flows affecting pipelines have created the will and funding for studies into both the identification and cause of slope failure locations as well as the means to 97 mitigate or protect the pipelines. Using case studies from BC, Gartner & Jakob (2020) created a methodology for conducting quantitative risk assessment for pipelines in steep creek environments. This type of risk assessment allows future developers to not only make better route selections, but also to calculate the likely success of mitigation methods. These types of studies will only benefit from the addition or robust data from geohazard caused pipeline incidents globally. However, accessing this data in Canada for planning purposes can be challenging. Criticisms have been made regarding the un-clear definitions of incidents and their causes globally (Porter et al., 2016) and domestically (Belvederesi et al., 2017), with different regulatory entities holding different datasets making collating incident data particularly challenging. Improvements that could be made to make geohazard identification based on past incidents more effective would include: consistent definitions, more details on the cause and trigger of the geohazard, better characterization of the geohazard type and size, the orientation of the pipeline relative to the hazard, and the coordinates of the failure sites so they can be cross referenced against geological data (Porter et al., 2016). Often in the event of a natural hazard caused incident, the collection of primary information may have been hindered by the event itself. It would be beneficial to researchers and future projects if pipeline operators would take time to update older records as more information is discovered and remove outdated or irrelevant information (Girgin & Kraussman, 2016). Newton et al., 2019 suggested that Additional tracking of cases where affirmative action has been taken to prevent pipeline failures will add greatly to this body of knowledge, such that learnings can be taken from near hits as well as incidents. There is increasing awareness, driven partially in reaction to incidents such as Zyometz for the need to develop a better baseline of knowledge to apply to safe route planning and 98 operations of pipelines in BC. Recently the BCOGC, in conjunction with the BC Oil and Gas Research and Innovation Society and BGC Engineering, published a northeast B.C. Landslide Susceptibility map to the BCOGC’s website for permit holders or stakeholders to consult when planning oil and gas activities in the area. The BCOGC has also worked with the UBC Pipeline Integrity Institute on projects to study: sloping ground effects, earthquake induced ground movements, geotechnical risk reduction, and monitoring loss of soil cover due to river scour. These types of projects, that bring together governments with private organizations and researchers, are an ideal way to promote organizational learning across and between industry and regulators. 99 4.4.4 Encana Sour Gas Pipeline Failure (Swan Wellsite) 2009 Figure 4.3. Location map of the sour gas pipeline incident Context Natural gas is often divided bilaterally into ‘sweet’ and ‘sour’ gas. The difference is in the hydrogen sulphide (H2S) content within the gas. Gas with little to no measurable H2S content is considered ‘sweet’, while ‘sour’ gas contains significant amounts of H2S or both H2S and CO2 (acid gas)(Allison et al., 2019). Sour gas is less desirable as it is associated with increased processing costs, corrosion challenges for pipelines, as well as negative human health impacts. H2S in toxic when inhaled in dangerous quantities and safe exposure requires constant air monitoring and the use of a full self-contained breathing apparatus where appropriate (CCOHS, 100 2017). Even from a safe distance, a sour gas leak is often noticeable from the smell, which is often likened to rotten eggs. Natural gas wells, facilities, and pipelines are designed as such to ensure that no H2S is released to the atmosphere during routine or non-routine operations (BCOGC, 2021a) In British Columbia, the predominant source of natural gas are shale gas plays, mostly located in the north east corner of the province. Shale gas, or ‘tight gas’ is natural gas that is trapped within shale substrate formations that have a low permeability. While a ‘conventional’ well flows naturally, shale gas wells are considered 'unconventional’ and require some sort of intervention to compromise the shale's natural impermeability and free the gas to be extracted. Since 2011 unconventionally sourced gas has surpassed gas production from conventional reservoirs in British Columbia and this trend continues to rise (NRCAN, 2017). Extracting shale gas or ‘unconventional gas’ is then primarily done via the method of hydraulic fracturing which is colloquially referred to as ‘fracking’. The process of hydraulic fracturing entails the drilling of a vertical well approximately two to three kilometres below the surface (CAPP, 2021) to reach the target geological formation, then drilling horizontally through the shale layer. The wellbore is then perforated to enable the natural gas to flow into the piping. A mix of predominantly water and sand is pumped down into the well at high pressure which further fractures the surrounding shale rock, freeing the natural gas to flow back up to the surface where it is collected and transported via pipelines. As the gas is extracted, there is often some amount of the fracturing sand that is carried in suspension. Over time this sand erodes the pipes, elbow-bends, and valves of gathering pipelines (the pipelines that transport the gas from the wellhead to the transmission pipeline or processing facility) and ultimately causes significant damage (Peng et al., 2016). Sand erosion is a significant concern for 101 operators and researchers have worked to model and better understand the role suspended sand plays in internal erosion on pipelines through the use of computational fluid models (Wee & Yap, 2019; Cuamatzi-Melendez et al., 2017; Kane et al., 2017; Peng et al., 2016; Zhang et al., 2016). Findings showed that pipeline bends or elbows are particularly vulnerable to erosion, but can be somewhat mitigated through adjusting the angle of the bend or increasing the diameter of the pipe. However, the length of the gathering line from the wellhead to the sand removal equipment remains vulnerable to being compromised and operators are expected to maintain appropriate monitoring. The Incident The following incident summary is taken from the BCOGC Failure Investigation Report issued on the 4th of February, 2010. On November 22, 2009 (a Sunday) at 08:38 am a pipeline adjacent to a well site near Pouce Coupe failed, releasing 30,000 m3 of sour natural gas into the atmosphere. Early that morning local residents had noticed the smell of the gas and a sound similar to a ‘jet flying overhead’ but had not reported any concerns, some assuming work was being done on the pipeline, and others unclear on the source of the smell and sound. At approximately 08:30 a resident driving through the area observed a gas cloud and called 911 after advising nearby residents to evacuate their homes. Residents took it upon themselves to notify the community and restrict vehicle access to the area. By 9:00 AM RCMP has been made aware of the situation and the fire service dispatch has been alerted. Between 9:05 and 9:10 the first alarms go off in the EnCana Control room, alerting an operator of an automatic valve closing in the vicinity due to a high H2S reading at the well. Between 9:30 and 10:00 AM, both local residents and the RCMP contact EnCana to inform them of a probable leak, and that residents are evacuating. 102 EnCana Operators who arrived on site beginning at 9:50 AM proceeded toward the broken pipeline conducting air monitoring to test for H2S levels but were unable to make it to the site safely and it was subsequently acknowledged that SCBAs would be needed to stop the flow of gas manually. At 10:45 EnCana notified the Ministry of Energy, Mines, Minerals and Petroleum Resources of the incident, which had been classified as a Level 1 Emergency. The well was successfully shut in by 10:45 AM and situation updates were made to the Ministry, the RCMP, and the Peace River Regional District. The Area The Swan Wellsite is located in the southern area of the Peace River Regional District, along the BC/Alberta border. The region is part of the boreal forest area and is centred by the Peace River that extends from the Rocky Mountains in northern BC to where it joins the Athabasca River in northern Alberta. The regional district includes the incorporated communities of Fort St. John, Dawson Creek, Tumbler Ridge and Chetwynd, which represent a substantial portion of the population of Northern BC. The Peace River District also represents the centre of the majority of BC’s natural gas wells and hydraulic fracturing activities. The town of Pouce Coupe, which was the closest to the pipeline rupture has a population of fewer than 800 people and approximately one quarter identifying with an aboriginal identity according to Statistics Canada (2016). The substantially larger community of Dawson Creek can be reached within 15 minutes on the highway. The Investigation One week after the incident, the BCOGC issued a formal request for an assessment of the cause of failure for the incident as well as a review of EnCana’s emergency management and response effectiveness. The failure analysis of the pipeline, conducted in a lab, determined the 103 cause of the failure to be significant internal erosion caused by the sand that is injected into the gas during fracture operation. Follow up investigation found that, for this particular well, EnCana had not aligned with its own policy for sand monitoring and the frequency of inline erosion assessments conducted were insufficient. Another aggravating factor was that while there was an automatic shut off valve adjacent to the well, it was located downstream of the failure site, making it ineffective to prevent this incident. There were also issues with the settings of the monitoring software that led to a delay in the warnings that notified EnCana staff of an issue. The leak flowed from the well, through the broken pipe for nearly 27 minutes before the first alarm was detected. The BCOGC assessment of EnCana’s emergency response performance found that the company had failed to fully comply with it’s published Emergency Response Plan, particularly in regard to communication both during and prior to the event. During the event delays in external notifications (57 minutes between visual confirmation of the leak and the call to the Provincial Emergency Program) compromised the efficiency of the response and were in contravention of both EnCana’s Emergency Response Plan and the Provinces Drilling and Production Regulations. Interviews with members of the community also showed a lack of communication with the community. EnCana did not notify ‘formally’ residents about the event until 71 minutes after the first alarms were sounded in the EnCana control room. This was well after many residents had voluntarily self-evacuated. There was also very little clarity among residents of the community regarding who to notify when the gas leak was first noticed early in the morning. While EnCana had previously released a Public Information Package intended to encourage 104 residents to call if they believe they smelled H2S in the area, this incident proved that the company had been ineffective in disseminating that information throughout the community. Actions Taken The BCOGC issued several requirements and recommendations to EnCana in light of the accident analysis findings. From an engineering perspective, there was an order for EnCana to place emergency shutdown valves within one metre of all wellheads in BC where internal sand abrasion might be an issue. This was intended to mitigate the ineffectiveness of an automated shutoff valve being located downstream of a rupture connected directly to a well. The BCOGC also required EnCana to present them with plans that outline additional control and monitoring plans for any wellheads where isolation was dependent on ambient H2S levels and located within three kilometres of a residence. This was intended to prevent another case of delayed alarm notifications. Overall there were additional requirements for EnCana to identify to the BCOGC where any other well sites may have not met sand clean up criteria and to present a plan of the future integrity management of those sites. To promote organizational learning within the company and the industry, the BCOGC issued a requirement for EnCana to include a review of the incident report, including the time taken for notifications, evacuations, and coordination with external agencies, in all emergency response training for employees and contractors for the following two years. They were also required to develop a regulatory training and awareness program for all employees and contractors that would clarify the role and regulatory authority of the BC Oil and Gas Commission and how to contact them and at what point it is necessary. To ensure public communication was improved with surrounding communities, EnCana was directed to review their existing public information program, make amendments where 105 warranted, and to put in place a method of evaluating the effectiveness of the program, the results of which were to be shared with the Commission. The 24-hour emergency communication number was also identified to be made clear on all documents, encouraging residents to contact the Provincial Emergency Plan immediately if they believe there is a leak nearby. This incident did not go unnoticed by the broader public. A little over a week after the BCOGC report was released, a letter was sent to the Minister for the Environment and the Commissioner of the BCOGC requesting a public inquiry into the occurrence, backed by over 25 NGOs, associations, and the West Moberly First Nation, along with residents from many of the surrounding Northern Communities (Hill & Campbell, 2010). The contents of the letter expressed the concern of local residents and community members over the time between the leak and EnCana’s emergency response actions and the lack of coordination with the local RCMP. The request was made to delay the finalization of the draft Consultation and Notification Regulation under the Oil and Gas Activities Act until steps had been taken to address concerns around the perceived risk to public health and safety that the pipeline was well represented. 4.4.5 Nig Creek Pipeline (Westcoast Energy Inc.) and Bonavista Energy Corporation (Bonavista) Pipeline Context Pipeline construction in British Columbia, often involves covering long distances of rugged, heavily forested and remote land. Part of the construction process involves clearing a corridor of trees for enough space to effectively lay out the pipes and dig deep enough to bury and string the line. These corridors have become increasingly recognized as having a complicated effect on local ecology, disrupting some species migration patterns, and providing 106 advantageous habitat or access for others. Suzuki & Parker (2019) found that activities associated with oil and gas development in the winter habitats of woodland caribou, an endangered species, can lower calf production and survival rates, while also increasing the rate of predation by making it easier for wolves to access the remote habitats (Latham et.al., 2011). Grizzly bears conversely, have been found to not avoid disturbed areas. Instead, they use them as a food source; their preferred vegetation preferentially grows in areas that have seen relatively recent disturbance (Sorensen et al., 2021). Female grizzly bears in particular seem to preferentially choose the edge habitat created by utilities corridors for their ranges, as it allows them to move faster and cover more ground (Stewart et al., 2013) These effects cannot only be considered in isolation. Increasing oil and gas development in the province has a cumulative effect on habitat fragmentation and animal migratory habits. Habitat fragmentation occurs when habitats are broken into smaller, isolated pieces, often by linear features such as pipelines, roads or power lines. This can be particularly problematic for certain species. Woodland caribou for example, have been found to require large, undisturbed forest patches to maintain their anti-predator strategies, and without it became more vulnerable (Lesmerises et al., 2013). Overall, increasing linear development in remote areas has been linked to lower biological diversity and altered ecosystem processes (Dunne & Quinn, 2009). BCs growing natural gas industry has implications beyond pipelines; it also leads to the creation of more access roads, seismic lines, and other associated infrastructure. These features and how they collectively impact the surrounding environment is increasingly a concern that is observed during the assessment process for new projects (BC EAO, 2018). One method utilized by pipeline companies to minimize both the cost of a project and the environmental impact of a new linear feature on the surrounding landscape, is to use existing 107 utility corridors. These corridors or right-of-ways are stretches of cleared land that already have power lines, pipelines or roads in place. Utilizing existing right-of-ways for pipelines is also being increasingly used in areas of developing urban density. Constructing a pipeline in an existing right-of-way allows the builders uninterrupted access for construction and and later, maintenance, which aids in reducing the overall cost of the project (Dey & Gupta, 1999). However, while the sharing of a right of way does increase the project's efficiency and reduces its environmental footprint, there is a degree of increased risk. The BCOG outlines the requirements for a pipeline sharing a right-of-way in its Emergency Management Manual (2021). The Hazard Planning Zone, the distance of possible impact from an incident, must consider the cumulative effect of each pipeline, using maximum licensed values. Emergency response notifications must also account for the other infrastructure utilizing the right-of-way. The primary concern for an incident that involves two natural gas pipelines running parallel in a right-of-way is the rupture of one pipe causing a ‘domino effect’ that impacts the other line. When this happens, the consequences tend to be significantly greater than those from the initial event (Cozzani et al., 2005). When a buried natural gas pipeline ruptures, the result is a crater caused by either the sudden rupture of a high-pressure pipeline, or by the explosive ignition of gas that has accumulated from a leak (Amaya-Gomez et al., 2018). If the released gas ignites, a fire can also subsequently develop in the crater (Giovanni Ramirez-Camacho et a., 2015). If the second pipeline in the right-of-way is outside the crater it will typically remain safe, protected by the surrounding soil (Silva et al., 2016). If, however, the parallel pipeline falls within the formed crater it will be subject to both the pressure and heat of the rupture, explosion, and fire. This can cause a domino effect, rupturing the adjacent pipeline and escalating the scale 108 of the incident and the impact on the surrounding environment (Giovanni Ramirez-Camacho et al., 2019). In Canada the distance between two buried parallel pipelines is not standardized. The CSA pipeline standard (CSA Z662:19 section 4.11.1) outlines the clearance requirements as “the designer shall give consideration to a) clearance required to perform construction, maintenance, and repair activities on the pipeline and other adjacent pipelines or buried objects; b) excavation activities (including trenchless excavation) in the same corridor; c) pipe movement during operation; d) protection and temporary support of the pipeline and adjacent buried objects during construction, maintenance or repair activities; e) interference between cathodic protection and grounding systems; and f) effect of operating temperature on adjacent buried objects”. Canadian pipeline companies and the CER reference the CSA Z662 standard for the distance between parallel natural gas pipelines, which in turn references the British Standard IGEM/TD/1 (Institution of Gas Engineers & Managers) documentation, table 6 in particular. In cases where the IGEM/TD/1 standards do not apply, it is suggested that the designer performs a crater analysis of the scope of displacement likely to be caused by a rupture (CSA Z662;19 section 4.11.6). Some studies have been done on the models that predict the crater size resulting from a natural gas pipeline incident: Leis et al., 2002; Acton et al., 2010; Silva et al., 2016. However, at this time there is no one industry standard. The focus of this case study is on an incident that occurred in Northern BC in 2013 and to date has been the most notable example of a domino effect on a natural gas pipeline in the province. The following is a summary of the TSB incident investigation and report (P12H0105). 109 Figure 4.4. Location map of Nig Creek pipeline incident. Nig Creek Pipeline Incident Near midnight on June 28th, 2012, Westcoast Energy Inc.’s (Westcoast) Nig Creek pipeline carrying sour gas ruptured and ignited, catching the surrounding forested area on fire. A pipeline owned by the Bonavista Energy Corporation (Bonavista) that was located in the same right-of-way, also carrying sour gas, ignited 25 minutes later. In total, approximately 962,000 m3 of gas was released and 1.6 hectares of the surrounding land was burned. The area of the Peace River Regional District the rupture occurred in was quite remote, with the nearest town being Buick, British Columbia, a population of only 58 people located 40 km away. Because of this there were no evacuations required. 110 The Area The rupture of the Nig Creek pipeline occurred in a remote area of the province, approximately 100 km north of Fort St. John, west of the Beatton River. The region lies in the Boreal forest, nearly halfway between the foothills of the Northern Rocky Mountain and the BC/Alberta Border. While there are no large communities in the area, it is a region of active oil and gas development, and accessible through industry service roads. The Pipelines Westcoast’s Nig Creek pipeline is a federally regulated pipeline that is part of the sour gas gathering system in northern BC. This particular section of pipeline sits between two booster stations (Nig Creek & Buick Creek) that smaller gathering lines feed into and send the compressed gas onwards to the McMahon gas processing plant located in the town of Taylor, BC. The Nig Creek pipeline was built in 1960, had an NEB approved maximum operating pressure (MOP) of 6,895 kPa, and was field-coated externally with an applied asphalt enamel coating. The MOP was based on a successful hydrostatic test in 1961. The hydrostatic test had never been repeated in the subsequent 51 years, however 3 inline inspections had been run in 1986, 1995, and in 2004 that resulted in repairs to the external coating and several sections of pipe being replaced to mitigate external corrosion. No testing historically had revealed any issues at the site of the rupture. The Bonavista pipeline is a smaller, shorter line, sharing a right of way with approximately 3 metres between the two pipelines. This 5.8 km provincially regulated pipeline came into service in 1967 with an approved operating pressure of 3,500 kPa and was coated with 111 extruded polyethylene during the manufacturing process. Opposite to the Nig Creek pipeline, the Bonavista pipeline is transporting sour gas north, rather than south. In the two years prior to the incident, the Nig Creek pipeline operated at an average pressure of 4,350 kPa with a maximum pressure of 6,628 kPa being recorded in 2011. When the incident occurred, the booster station closest to the incident (Nig Creek) was not in operation and there was no gas flowing in the pipeline because of an unplanned outage at the McMahon gas processing plant. With the interruption of gas flow in the lines because of the outage, gas being produced upstream continued to accumulate in the gathering lines. This should have resulted in a steady increase in pressure in the upstream lines that would plateau at a uniform pressure managed by pressure control devices, activated at set points based on the approved operating pressure for the pipeline. The pressure in the Nig Creek line increased from 4,100 kPa the morning of the plant outage to 6,656 kPa, which was followed by a rapid decompression at 11:00PM. The Incident The Westcoast pipeline is monitored and controlled by a Supervisory Control and Data Acquisition (SCADA) system that provides operational staff with real-time information on pressure information and operating parameters for the various compressors and facilities throughout the system. This allows them to make adjustments to compression, pressure control, and facilities as required. Between 11:14 PM and 11:23 PM on June 28th, two medium priority low pressure alarms were reported by the SCADA system. The reports display on a screen that also shows every other warning or alarm that might have come up for the entirety of the pipeline system. In the same time period, a controller monitoring the system was focusing on managing rising pressure on other systems that were nearing their maximum operating pressure. The 112 Westcoast controller was first made aware of the Nig Creek pressure drop by phone, as other gas producers reached out to ask for the system to come back on line. The pressure drop was initially thought by operators monitoring the SCADA data to be a result of the overall system managing the pressure in the line. At 11:30 PM, Bonavista, the operator of the pipeline that runs parallel to West Coast's Nig Creek Line, was contacted by a local landowner to report a large fire in the area. Upon reviewing their own SCADA documentation, they also noticed a drop in pressure, which had not triggered any alarms. At this point, Bonavista staff contacted the Westcoast controller to alert them of the fire on their line. Westcoast immediately initiated the company's response procedures; personnel were dispatched to the area and over the subsequent two hours, a series of gas isolation valves on both lines were closed to cut off any further gas supply to the fire. The fire finally burned out due to a lack of fuel supply at 4:30 AM on June 29th. Once the pipeline was no longer on fire, attention turned to managing the forest fire that had been started by the initial explosion. Water was airdropped and the fire was extinguished within 30 minutes. An examination of the site revealed a 17m x 7.6m crater had been formed, with sections of the pipeline being ejected as far as 20m away. Within the crater were the remains of the Nig Creek pipeline, as well as the damaged length of the Bonavista line. The coating on both pipelines where they had been exposed to fire was completely destroyed and both pipelines had ruptured. The investigation showed that Westcoast’s Nig Creek line had ruptured due to a pre-existing hook crack that had caused a fracture along the seam of a pipe joint. A hook crack, named for it’s curved shape is a common type of defect in welds where an inclined rack is formed a couple millimetres away from the weld center line, and follows the lamination planes of the base plate (Otegui, 2014). The subsequent fire degraded the structural integrity of the 113 adjacent Bonavista pipeline, until it too ruptured and continued to feed the fire. Lab examinations of the cracked section of the Nig Creek pipeline did not find any evidence of corrosion or environmental damage, rather it was theorized that the hook crack had been created during the manufacturing process. The Investigation The TSB analysis of the incident found that despite never exceeding the maximum operating pressure, the hook crack that had gradually been worsening over time, had reduced the integrity of the pipe, so that the increase in pressure from the McMahon plant outage overwhelmed the pipe's internal capacity. The initial SCADA medium priority warning that was issued when the line began losing pressure showed up on a screen, amidst several other medium priority warnings for the whole system. In conjunction with the controller managing multiple systems and responding to calls from other operators to come back on-line, this resulted in a 16-minute delay of the issue being noticed. The TSB report noted that the excessive workload of a single systems controller, when not managed, poses a risk in the timely response to an emergency. The hook crack that caused the event was overlooked for multiple reasons. Pipelines of the vintage of the Nig Creek line, those welded using a low-frequency electric resistance welding process, have an acknowledged increased risk of seam defects. However, the Nig Creek line had few of these welds and passed its initial hydrostatic testing in 1960 and 1961. The line was never hydrostatically tested again and was not subject to any crack detection or mitigation programs, as it was determined to be low risk given its operating environment and composition. While in-line inspections were run based on Westcoast’s pipeline integrity management program, the technology used is primarily to detect corrosions, not cracks. 114 Resulting Actions In response to the findings of the TSB report, Westcoast Energy conducted a hydrostatic test on the pipeline to a minimum pressure test of 125% of the maximum operating pressure. This test resulted in no further faults being discovered. The company also scheduled in-line inspection with technology specifically intended for crack detection. Lastly, there was a review of the SCADA alarm naming and grouping, with the intent of managing the number of alarms that a controller monitors, to hopefully make it easier for similar alarms to be acknowledged immediately in the future. Conclusion While better operating systems and real time monitoring technologies have improved the quality of data operators have to make decisions, they have also dramatically increased the quantity of data that needs to be reviewed. In the case of the Nig Creek incident, the volume of SCADA data and warning messages the operator was expected to oversee exceeded the capacity of the single worker and the relevant information that could have prevented the breach was lost among all the other messaging. In response Westcoast Energy made efforts to re-align the messaging software of the system after the incident and reduce the number of alerts a single operator is expected to observe. That the operators of the Bonavista pipeline were not aware of an issue until a local called to report a fire suggests issues with data monitoring and software were prevalent there as well. As systems become more complicated there needs to be an acknowledgment that the job of the operator may also become more demanding and continually adding expectations to a task without simultaneously adding support will always prove, ultimately, unsustainable. 115 This incident also outlined some existing flaws in the lines of communications between pipeline operators. While there are reporting requirements in operators Incident Management Plans for contacting regulators, there is nothing to regulate inter-company communications, even when sharing a right of way. The additional risk potential of a cascading effect of multiple ruptures on more than one line should be incorporated into risk assessments in emergency management plans, which could be created with, or at least shared with the other companies sharing the right-of-way. While there is a perception supported by Canadian operators that, as long as corrosion is avoided, the older pipelines are no riskier than a new line, in this case that was not accurate. The welding method used on older sections of pipelines has an increased likelihood for the presence of seam defects, like hook cracks, that increase the risk of failures during the pipelines service (TSB, 2012). While replacing older sections of the pipeline that are ostensibly in good operating conditions may be financially unfavourable, appropriate technologies to detect any cracks forming must be used by knowledgeable people at a high enough frequency to prevent failures. Added attention is particularly merited in situations where there is a high likelihood of a cascading effect such as in right-of-way’s with multiple pipelines. While the damages in this case were largely mitigated by the remoteness of the incident, a similar rupture with parallel running pipelines in an urban or roadside setting could cause significant damage. 4.4.6 Case Study of Stress Corrosion Cracking - Westcoast Energy Prince George Incident Stress corrosion cracking and Canadian Pipelines Globally human, or third-party intervention is the most common source of pipeline incidents, whether it is from accidental contact or interdiction (Guo et al., 2018; Muhlbauer, 116 2004). In Canada, depending on the reporting source, corrosion and third-party interference are the most common forms of pipeline failure (Barros de Cunha, 2016; CEPA, 2016). Corrosion in pipelines refers to a gradual loss or deformation of the wall metal that can eventually lead to a failure of the line. This corrosion primarily presents itself in three ways: 1. External Corrosion: metal corrodes due to contact with atmosphere or through contact with subsurface materials in the case of buried pipelines. Subsurface external corrosion is considered more dangerous due to the complicated mechanisms involved (Senouci et al., 2014). External corrosion is usually due to a failure of first the pipeline coating that prevents contact with the wet soil, then secondly a failed or insufficient cathodic protection (CAPP, 2018). 2. Internal Corrosion: the chemical reaction between the pipeline material and the transported fluids or gases degrades the inner surface of the pipeline (Dey et al., 2004). This type of corrosion is dependent on the type of material being transported and research suggests that wet gas causes more issues than dry (Barros de Cunha, 2016). As the hydrogen sulphide and carbon dioxide content of the natural gas are also considered contributing factors, this medium of corrosion is more likely to occur with sour gas or in close proximity to the reservoir (CAPP, 2018). 3. Stress Corrosion Cracking (SCC): cracks in the metal form and grow, typically on the exterior of the pipeline, due to the combined forces of a reactive environment, susceptible microstructure and a stress (static and tensile) (Gamboa, Linton & Law, 2008; Shoji, Lu & Peng, 2011). The corrosion also implies that the protective coating and cathodic protection for the pipeline has failed. 117 Stress corrosion cracking (SCC) of buried pipelines has been a recognized hazard for more than 50 years. The issue was first identified in the pipeline industry when an underground pipeline failed due to SCC in 1965 in Natchitoches, Louisiana, killing 17 people (Kentish, 2007). The subsequent investigation found that the rupture occurred where there was a colony of cracks on the exterior of the pipeline. This incident provoked a detailed investigation and an increase in funding for research into understanding SCC. Ultimately the increased scrutiny influenced the United States government to increase the regulation of onshore pipeline safety beginning in 1970 (Beavers & Bubnik, 2017). In the following decades many more pipeline failures were accredited to SCC; investigations consistently displayed cracks that were initiated where the soil made contact and then ran parallel to the longitudinal axis of the pipe (Shipilov & Le May, 2006). SCC failures were notable in that, while the average failure age of a pipeline was between 15-20 years, the first failures from SCC were from lines that had been in operation for over 40 years (Krasovskii, Lokhman & Orynyak, 2012). Stress corrosion cracks, while often found near welds, are not necessarily attributed to them and occur on both pipelines without any corrosion protection as well as lines with quality protective coating and cathodic protection (Shipilov & Le May, 2006). The cracks are often found in ‘colonies’ that form on external surface sites where there is already some pitting, disbonding, or general corrosion (Zvirko et al., 2016) Since its discovery, SCC has been identified as a cause of pipeline failures throughout the world with incidents being documented in Australia, Canada, Iran (Meresht, Farahani & Neshati, 2011; Abedi & Adibi, 2007), Iraq, Italy, Pakistan (Hasan & Ahmed), Saudi Arabia, China (Young-Jim et al., 2005) the former USSR (Zheng et al., 2011) and modern Russia 118 (Ryakhovskikh et al., 2018) . Further research into the subject identified two distinct types of SCC: high pH and near-neutral pH SCC, also called low-pH SCC. High pH SCC can occur in concentrated solutions of bicarbonate-carbonate with a pH of ~9 to 11 (Javidi & Bahalaou, 2014). The process displays an intergranular or intercrystalline (Krasovskii, Lokhman & Orynyak, 2012) morphology with branching cracks that appear ‘sharp’ with little lateral corrosion (Fan et al., 2003). The precise mechanisms of high pH SCC are still actively being studied (Song, 2009; Oskuie et al., 2012; Lavigne et al., 2014; Griggs et al., 2016) with the most frequent explanation being that a high enough concentration of carbonate passivates the pipe surface and the intergranular cracking happens via anodic dissolution mechanism (Arafin & Szpunar, 2009, Wan & Atrens, 2003). This carbonate concentration is caused when a sufficiently high cathodic potential is applied and water dissociates to form hydroxyl ions, creating an environment capable of combining the surrounding dissolved carbon dioxide to form carbonate and bicarbonate ions (Roccisano & Ghomashchi, 2020). This form of SCC can be found on pipelines with subpar cathodic protection (Zheng et al., 2011) and is often referred to as “Classical SCC” (Gu et al., 1999) and has been the subject of most studies. The second type of SCC, known as ‘near-neutral SCC’ is where cracking has occurred in proximity to ground water with a relatively low pH of ~6.5, just slightly below neutral. The cracks from this process are transgranular, or transcrystalline (Krasovskii, Lokhman & Orynyak, 2012), wider with little to no branching, have more lateral corrosion and hydrogen-induced strain hardening along the sides of the cracks than from a higher pH level (Fan et al., 2003). Near-neutral SCC often happens under the disbonded coating of buried pipelines and has been linked to hydrogen, carbon dioxide and sulphate-reducing bacteria (Javidi & Bahalaou, 2014). These 119 can often be found in groundwater and near-neutral SCC has been linked to areas of poorly drained soils (Zvirko et al., 2016). In both near-neutral and high pH SCC, the cracks occur in longitudinal colonies that over time line up to form extended shallow flaws that can lead to a material failure and pipeline rupture (Beavers & Harle, 2001). Near-neutral SCC has proven more challenging to study in laboratory environments and scientists are still striving for a complete understanding of the processes that cause it (Liu et al., 2012). In all cases of SCC there are three conditions that must be met simultaneously: the material must be susceptible to SCC (metallurgy), tensile stresses must be present, and the environmental conditions must promote crack development (Beavers & Hale, 2001). Ryakhovskikh et al., 2018 studied reports of SCC related pipeline failures in Russia and the former USSR. High-pH SCC was observed in gas pipelines running through the arid climates of Central Asia and Kazakhstan while investigations of pipe samples from incidents in Western Siberia, the Urals, and North-western Russia showed evidence of near-neutral SCC. No failures due to SCC were reported from the southern regions of the country. This would suggest that climate and environment have a significant influence on the propensity for SCC developing. Of course, not all pipelines are made of the exact same material and extensive testing has been done to determine the effect of metallurgy on SCC. Newman (2010) found that SCC on X-65 carbon steels in near-neutral-pH water can usually be traced to an increased tensile stress; dynamic loading such as freeze-thaw cycles increase the materials susceptibility. Stronger steel grades however developed SCC without the need for this ‘fatiguing’ aspect. There is still considerable study being done in these areas. 120 SCC development on a pipeline is dependent on a variety of factors including the levels and fluctuations of stress and loading, temperature, metallurgy and the pH and chemical makeup of the surrounding environment. However, for all SCC the process is initiated with the compromise of the coating. Steel has been used in pipeline construction since the 1800s and modern gas pipelines are built with large-diameter, thin-walled pipes of a high-strength steel designed to operate under high pressure (Kui-Zhu, 2015). Early evidence of the steel corroding in the ground guided manufacturers to begin adding external coatings to the pipelines. Early coatings were made out of tar, coal, and other readily available materials and were intended to create a ‘barrier’ between the pipeline and the surrounding environment which was relatively successful (Kiefer & Trench, 2001). Changing technologies throughout the 20th century led to newer coatings like fusion epoxy bonded, and urethane-based compounds that have a much lower rate of disbonding and are more effective at preventing currents from reaching the steel (Meresht et al., 2011). These modern coatings are used in conjunction with cathodic protection. Cathodic protection involves the application of a direct current to the surface of the metal to shift the electrochemical from a corroding state to a polarised, non-corroding state. This combination is generally considered to be the best engineering methods to reduce SCC potential and are practiced globally by industry. SCC became a particular concern in Canada in the mid to late 1990s. From 1977 to 1996, SCC caused 22 pipeline failures in Canada including 12 ruptures and 10 leaks (NEB, 1996). Initial concern about SCC led to the National Energy Board (NEB) conducting an inquiry in 1993; the findings at the time was that SCC was being managed sufficiently by industry (NEB, 1996). However, two large ruptures that resulted in fire on the TransCanada Pipeline System in 121 1995, along with a growing awareness of the prevalence of SCC, led to the initiation of a second, much broader national inquiry in 1995, the first of its size in the world on SCC (Cheng, 2013). The inquiry brought together industry members from the Canadian Energy Pipeline Association (CEPA), academics and regulators to analyze technical reports and incident findings in order to understand if SCC was a problem that could be resolved. One of the major findings of the inquiry was that most of the SCC-related incidents in Canada occurred on pipelines that were installed between 1968 and 1973 (Shipilov & May, 2006). The commonality between these failures was found to be the polyethylene tape that was commonly used as a protective coating during that time period. The inquiry found that polyethylene tape had a tendency to disbond or separate from the pipeline, which allowed moisture in (NEB, 1996) and corrosion to occur. The committee predicted that SCC would become less of an issue as these older pipelines were phased out; the newer coatings like fusion bonded epoxy were of less concern. Canadian pipeline companies had already committed considerable funding to resolve SCC issues with CEPA members committing $4.8 million in research and $30 million on pipeline maintenance related to SCC (Shipilov & May, 2006). The recommendations at the outset of the inquiry was for a continuation of SCC research, changes to pipeline design, the creation of an SCC database, improved emergency response practices and the implementation of an SCC management program by the pipeline companies (NEB, 1996). Research has continued in Canada and beyond, as more nations recognized similar issues in their pipeline infrastructure. An SCC database was subsequently created and managed by the National Energy Board (NEB). As of December 2014 more than 800 crack colonies were listed in the NEB “significant SCC” database dating back to 1997 (CEPA, 2015). Out of the entries that had 122 coating information, the vast majority (89%) were found on single or double-wrapped polyethylene tape coating. The remaining 11% were associated with asphalt coating, and only one entry was found in reference to a coal-tar coated line. The remaining recommendations were targeted by CEPA with the creation of the Stress Corrosion Cracking Recommended Practices Manual. The creation of the Stress Corrosion Cracking Recommended Practices Manual by CEPA was the most significant product resulting from the national inquiry. The manual, first published in 1997, is a synthesis of all the best practices for industry, based on both experience and academic input. Now on its 3rd edition (2015), the manual has become the standard pipeline companies are held to in terms of SCC management in Canada. The primary function of the manual is to provide the relevant background information and recommendations to support the development of a robust SCC Management Program for pipeline companies. The SCC Management program is generally considered a subset of the broader Pipeline Integrity Management (PIM) program, fundamental to a pipeline's safe operation and maintenance. A PIM program incorporates the concepts of failure prevention, inspection and repair strategies, products, practices, and services that help operators maximize the functional lifetime of a pipeline (Kishawy and Gabbar, 2010) . Considering a pipelines full lifecycle, an integrity management program entails: (i) a means of identifying likely failure modes for all sections of pipeline; (ii) a repair or replacement criteria; (iii) assessment procedures that are maintained throughout the pipelines operation; and (iv) a process to review the results of integrity assessments (Amaya-Gomez et al., 2019). The program should include the collection, integration, and analysis of all information related to the design, construction, operation, and 123 maintenance of the program, and importantly, a means of relating that information back to the operator (Cheng, 2013). The use of an integrity management program for pipelines in Canada is entrenched in both CEPA and the CSA and is enforced by provincial and federal regulators. The SCC management plan as outlined by CEPA (2007) is based on three concepts: (1) risk-based decisions, (2) the impact of the SCC lifecycle on management methods, and (3) representative SCC data for a pipeline segment. The risk-based decisions in an SCC management plan incorporate risk assessments of pipeline operations and the use of risk-ranking models and software. Decisions regarding pipeline inspection priorities and mitigation strategies are based on quantitative data that provides information on the probabilities of problems occurring on the line. It is not feasible to inspect or continually monitor every inch of a pipeline, so operators segment the line and prioritize them based on the likelihood of SCC development. Some attributes that are considered in the segmentation would be the age of the pipeline and the season of construction, pipeline alignment, operating temperature, proximity to a pump station, the terrain, and the soil type proximal to the line (CEPA, 2007). All of these factors influence the likelihood of SCC developing, resulting in these segments of the pipeline being a greater priority for regular assessment and monitoring. The following is a summary of the Transportation Safety Board safety investigation P18H0088 (2020). 124 Figure 4.5. Location map of Prince George pipeline incident. The Area Prince George is considered the largest city in Northern BC with a population of approximately 86,000 people and is located in the Interior Plateau region. Geographically, the city sits nearly centred in the middle of the province, halfway between the coast and the BC/Alberta border, and halfway between the southern Border with the United States and the northern border with the Yukon Territory with two major highways running north-south and east-west through the community. The city sits on the traditional lands of the Lheidli T’enneh First Nation and is near the confluence of the Nechako and Fraser Rivers. Traditionally the town 125 has relied heavily on a forest-based economy, but in more recent years has diversified across other sectors including oil and gas as well as more secondary industries such as manufacturing. Outside of the town the region is typified by a sub-boreal spruce biogeoclimatic zone with a mixture of conifer and deciduous type trees at an elevation of 575 m asl. The Incident On October 9th, 2018, at approximately 5:30 PM, a pipeline carrying sweet natural gas ruptured approximately 13 km northeast of Prince George, BC. The pipeline is part of the Westcoast Energy Inc. System that is a federally regulated network of natural gas gathering and transmission lines operated by Enbridge Inc. The pipeline section was completed in 1972 and approved for operation by the National Energy Board (NEB) after passing a hydrostatic test in October of 1972. The line was coated in polyethylene tape for corrosion control and was further protected from corrosion with a current cathodic protection (CP) system. At the time of the incident the pipeline was operating under normal operating pressures that were approved by the NEB. The first sign of an incident occurring was a call from an off-duty Westcoast employee to the Enbridge Calgary Gas Control (CGC) to alert them of a loud noise and fire near Shelley, BC. With their monitoring software the CGC subsequently noticed a rapid decrease in the suction pressures at their compressors on the pipeline in that area. A local technician was sent to investigate and the CGC initiated a remote shutdown of the compressor station. At 5:40 PM, Westcoast’s emergency response plan was activated, and by 6:00 PM, both Pembina and FortisBC, who had infrastructure in the area, had been notified of the explosion. The pipeline segment had been isolated and Prince George Fire Rescue was on scene. By 7:00 PM, federal, 126 provincial, and local regulators had been notified of the occurrence and the RCMP helicopter had surveyed the site. It was estimated that nearly 140 million standard cubic feet (MMscf) of natural gas was released. The Response The primary concern was public safety, particularly because of the explosion and consequent fire. 125 residents in the proximity were evacuated including the 60 members of the Lheidli T’enneh First Nation who self-evacuated. Local fire rescue arrived on site quickly but had to wait for the pipeline section to be isolated to remove the continuous source of fuel before the fire could be extinguished. The fire and explosion affected an area of about 52,000m2 and created a crater approximately 35m long, 13m wide and 9m deep. The explosion also ejected sections of the pipe, the farthest of which was found by investigators about 25m northwest of the crater. The coating was nonexistent, presumably burned off by the heat of the fire. There was another buried pipeline that ran adjacent to the ruptured line. The second line was not running any product at the time of the incident and did not rupture, however there was heat damage to the line that required remediation (replacement). The environmental damage from the incident was confined to tree and soil damage in the immediate area of the crater and there was no private property damaged or any injuries. The primary immediate consequence of the line failure was the interruption of gas supply to the consumer market, a product that is commonly used as a heating fuel in northern BC. The FortisBC system experienced a supply shortage, with some customers being temporarily cut off entirely. Reduced supply continued to be an issue for several months, with Fortis customers being asked to conserve their gas use over the winter. 127 The Investigation Sections of the pipeline adjacent to the rupture were lab analyzed and several indications of SCC were found on the outside surface of the metal. It was determined that the SCC colonies had grown over time in a near-neutral pH environment and gradually formed into a larger single crack that catastrophically reduced the load-bearing capacity on the steel, resulting in a rupture. The polyethylene tape on this segment of the pipeline had lost adhesion from the pipe surface, protecting the pipe from the CP system intended to prevent SCC which allowed moisture to gather and create an environment for SCC to develop. Over time, the SCC compromised the load-bearing capacity of the pipeline steel. As a part of the investigation Westcoast Energy Inc / Enbridge’s SCC Integrity management plan, SCC management plan, and emergency response plan were all evaluated. In 2017, Westcoast’s SCC hazard management plan had identified near-neutral SCC as a hazard for the relevant pipeline section, rating it as a second level risk based on previous in-line inspection reports from 2003 and 2008. No SCC cracks were identified during those inspections. The maximum allowed interval between in-line inspections was nine years, extended to ten years during the interval, with the next inspection scheduled for 2017. The nine-year interval was based on Westcoast’s crack growth rate models, however the model did not account for the additional uncertainty of crack propagation over the additional year. The inspection was deferred in 2017, put off until the fall of 2018, allowing the developing cracks to go unnoticed until the failure. The TSB found Westcoast’s emergency response plan to generally satisfy the requirements to address evacuation areas, routes, and notifications. The one criticism was that 128 while federally regulated companies are required to hold emergency response exercised every three years, in the four years prior to the occurrence the Lheidli T’enneh First Nation, other communities, and other pipeline operators in the area had not been included with the government agencies, local emergency response and mutual aid partners that did attend the exercise. The TSB noted that if all potentially affected stakeholders are not involved with periodic exercises, it increases the risk of gaps in the emergency response plans. The report (TSB, 2020) concludes that the main contributing factors to the event were an insufficient crack growth model that underestimated the uncertainties in the measured values, resulting in faster crack growth than had been predicted. The delay of the in-line inspection would have likely detected the fault. The TSB recommended to Westcoast that based on the 500 km of SCC vulnerable polyethylene coated tape sections of pipeline on their system, they may wish to review their SCC management practices (TSB, 2019). The CER, then operating as the NEB, determined that while Westcoast was allowed to defer their in-line inspection by a year, it required the submission of a Standard Operating Practice Waiver and Technical Assessment which would have been a multi-step process that addressed safety. Neither of these documents were found to have been completed. With no justification for the delay of the inspection beyond the prescribed time interval, CER charged Westcoast with being in violation of a CER regulatory requirement and not adhering to their integrity management plan; they were fined $40,000 in September of 2020 (CER, 2020). Resulting Actions In response to the event, Westcoast made several adjustments to their stress corrosion management practices. SCC growth rates were adjusted to better reflect industry knowledge 129 about pipelines of similar age, material, and coatings, so growth rate predictions would be more accurate. They also increased the safety buffer on small flaws to ensure that they would not be missed in subsequent inspections and reduced the allowable inspection interval to 6 years. Beyond the technical and inspection updates, Westcoast implemented program improvements within their integrity management program to ensure that critical decisions would have more oversight and independent approvals. Improved tracking of any technical assessments and in-line inspection deferrals was also made a priority, along with the invitations and participation of stakeholders in full-scale exercises. Public reaction to the incident was driven by media coverage that significantly outpaced other incidents in BC (based on the number of news articles from both large and small media outlets). In particular, local residents and members of the Lheidli T’enneh First Nation felt endangered by the incident (CBC, 2019). The Lheidli T’enneh First Nation filed a civil claim against Enbridge, citing “serious and constant distress and anguish” for members and the company’s failure to adequately communicate the cause of the explosion and its aftermath (CBC, 2019). Both the industry and regulators alike were criticised in the aftermath for insufficient information sharing with the communities that were involved in the response. The Canada Energy Regulator (CER) is in an ongoing process to develop programs that measure pipeline response understanding and literacy in communities in relevant areas through canvassing community members such as fire and police chiefs. Conclusion The rupture of the Westcoast gas line near Prince George illustrates that while great improvements have been made in our understanding and awareness of SCC as a risk, pipeline 130 operators have not successfully mitigated the issue. In BC, there are hundreds of kilometers of aging pipeline that have field applied-polyethylene tape coatings which have been proven to increase the likelihood of SCC in comparison to other, more modern coating types (CEPA, 2015). A significant portion of Canada’s federally regulated gas lines were originally constructed more than 40 years ago, and while sections are replaced as needed, much of the system exceeds the 10 year buffer for SCC concern with certain coatings (PHMSA, 2008). Updating vast volumes of infrastructure quickly is unfeasible for pipeline companies for financial reasons. What operators can better control are the management programs they have in place to mitigate these increased risk factors. Enbridge, Westcoasts parent company, has consistently expressed the belief that the pace of new detection technologies for issues like SCC easily outpaces the damage inherent to the aging infrastructure (The Globe & Mail, 2011). However, this belief is dependent on the inspection technologies being used as intended and regularly enough to identify developing issues. This was not the case for this incident. While engineering controls like cathodic protection and inline inspections greatly reduce the risk of corrosion on pipelines, a robust pipeline integrity management plan that incorporates SCC management strategies is an operator's primary form of institutional control. The most effective plan is one that needs to be updated and evaluated often. No amount of tools or technologies will prevent an incident if the people or company operating the system are not working cooperatively to reduce risks wherever possible. The incident management plan that was in place had a maximum inspection interval that was allowed to be extended without any record of a formal technical assessment process. This could imply that either there was a failure in documentation or that the decision was one made 131 without oversight and no documentation was created. A decision to extend beyond the maximum safety threshold should, if ever, be made based on a reasoned and scientific assessment, and as outlined by company policy should have had more oversight. Ideally, inspections would be occurring in advance of the maximum allotted time. To use an analogy, it is similar to driving speed limits. The posted limit is intended to be the absolute maximum in ideal conditions (clear visibility and dry roads), any aggravating factors and speed should be reduced. It is important that the pipeline operators are not made to feel that they are pressured beyond tolerance with additional work to the point that safety processes are deferred. The failure in this case was not in an inadequate management plan, but rather in the failure to implement it. At some point a decision was made that the risk of consequence of an incident was lower than the risk of the inconvenience to schedule the inspection. The experience of regulators with this form of incident did aid in the investigation into the root causes of the rupture. Lab and field analysis allowed for a detailed understanding of how the incident occurred and will further guide policies regarding these types of polyethylene tape coated pipelines that are still in operation throughout the province. Aside from investigation, regulators also took punitive action against Westcoast Energy with the $40,000 dollar fine. This was in addition to any costs derived from the loss of product, infrastructure damage and service interruption. While this cost seems low for an incident that had international supply ramifications (EIA, 2018), it likely reflected the lack of public property damage and any human injury. If the cost and public attention is enough to prevent further delays of safety inspections on these and similar lines will only become evident over time. 132 4.4.7 Conclusion As shown by the progressive incident analysis used as case studies for this thesis, there has been undeniably improvements over time to British Columbia's natural gas pipeline safety and safe operating procedures. Lessons have been learned by both regulators and industry that are distilled to other pipeline operations through communication, reporting, risk awareness, and organizational learning. The primary avenues in which these case studies show the applied learning of BC’s pipeline learning from incidents are: technology, integrity management policies, and communication, both between regulators, with industry, and with the broader public. The relatively slow pace of technological improvement of pipelines can be subject of consternation. As a resource that is intended to be installed, then merely managed for the subsequent half century, there is a finite amount of room to engineer improvements for the pipeline itself. Technological improvements in pipeline safety in BC over time, have therefore come more in the form of improvements to the measuring, monitoring and assessment tools that operators use to assess the integrity of the lines. The main improvements to monitoring pipeline systems have been the adaptation of real-time monitoring technologies and improvements to the Supervisory Control and Data Acquisition (SCADA) systems. Pipeline SCADA systems perform monitoring and control; transmitting the information and data required for the operation of pipeline facilities through communication networks to a centralized control point. This allows a relatively small number of operators to continuously monitor a large network of pipelines, with the network alarming where there might be an issue in development (i.e. a pressure or temperature change). SCADA technologies continue to improve, connecting better monitoring and increasingly improved security. However as shown by both the 133 Westcoast Prince George Incident and the Nig Creek / Bonavista Incident, they are not infallible. The case studies used in this thesis expose the fragility of a monitoring system, which is often the human component. While SCADA systems continue to improve, there is no system to date that can completely autonomously and safely run a pipeline operating system. These operations still require the input of human knowledge, awareness, and experience. There is a continued risk of companies taking for granted that more notifications and alarms should make it easier for a minimal operation staff to oversee, when often the opposite can be true; splitting attention and making it more difficult to discern the truly serious alarms. The other primary change in pipeline monitoring technologies over the course of the case studies evaluated, is the development of smart pipeline inspection gauges, or PIGs. Smart PIGs, which are in-line sensors that run through the pipeline and are equipped to diagnose a variety of deformations to the metal including metal loss, cracks and corrosion. Modern PIGs are also equipped with GPS trackers that can communicate precisely where in the line problems were detected. The routine use of PIGs to inspect pipelines has made it possible to detect causes of pipeline failure such as stress-corrosion cracking much earlier, and by replacing the identified problem sections of line, prevent incidents. The primary flaw with these systems, similar to SCADA systems, is human error. Sensors are only able to mitigate incidents where they are used frequently enough to detect developing issues before they compromise the pipeline. This was one of the primary issues in the case of the Westcoast Energy Inc Prince George incident. However the improvement of these devices, particularly in regards to stress-corrosion cracking, shows an industry understanding of an issue that was researched collaboratively by industry and regulatory representatives and generated applied lessons. 134 A more basic, but equally important engineering development over time, and one of the most marked differences between the Monias pipeline incident report from 1997 and all the subsequent incidents was the incorporation of remote shut-off valves on pipelines. The Monias incident report describes flying personnel out to the pipeline via helicopters to manually turn off valves in order to cut off the flow of natural gas to the leak. In all of the subsequent responses, valves were able to be remotely activated. This is a singular example of pipeline engineering improving response capabilities and overall safety over time. While pipelines have essentially not changed dramatically in the previous half century, British Columbia’s pipeline industry has incorporated technological improvements that were able to improve pipeline safety and response. Other changes to the industry in response to incidents have been related more to policy development such as integrity management. Integrity management plans (IMPs) have become central to the pipeline safety landscape in British Columbia, and throughout Canada over time. Both the provincial and federal regulators have increasingly strict legal requirements of operators to create, maintain, and disclose their integrity management plans. In BC IMPs were made a regulatory requirement in 1999 and the BCOGC, under Section 7 of the Pipeline Regulation, requires every permit holder (licensed operator) planning, designing, procuring, constructing, operating, maintaining, or abandoning pipeline infrastructure within the province to have a fully developed and implemented Integrity Management Program for Pipelines (IMPP) (BCOGC, 2017). The BCOGC began auditing operators’ IMPP in 2011., and every year since operators are selected by a risk-based criteria to participate in this process. Between 10 and 20 operators each year are selected for an audit that assesses companies for areas of weakness in the high priority categories of: Inspection Maintenance and Monitoring; Risk Assessment; Training and Competency; and 135 Incident Investigation and Learning (BCOGC, 2020). Any issues with the audits, generate corrective action plans that operators must implement. Similarly, the Canada Energy Regulator manages a compliance oversight program that assigns a pipeline operator company a score based on their response capabilities, IMPs and emergency response plans. Where there are unknown factors related to a company's response capacity, the score assigned is the highest risk level. These companies then are more likely to receive additional oversight. The planned compliance activities, informed by incident reviews and compliance activities for a feedback loop that ultimately lead back to planning. Through this methodology the industry and regulators are able to incorporate learnings from both incidents and near misses. Integrity Management Plans represent the best practice for a company’s conforming and safe management of their pipeline assets, and also become the framework against which an operator is assessed by regulators in the event of an incident. For both the Encana sour gas incident and the Westcoast Energy Inc Prince George incident, failure to follow the integrity management plan, as it had been presented, was cited as one of the primary causes of the incident. The IMP’s for both incidents had been previously approved by regulators. This suggests that while integrity management plans in and of themselves may have become more comprehensive and progressive over time, there are still safety issues to overcome within the corporate culture and personnel training programs for gas pipeline operators in BC. A plan is only a good plan if it is actually followed. Aside from the development of IMP’s, in the last two and a half decades there has been a drastic change in the expectations and results surrounding pipeline accident investigations. This is particularly evident when comparing the reports from the Monias incident in 1997 and the 136 Westcoast Energy Inc. Prince George Incident in 2018. The TSB report for Monias consisted of a five page document with no mention of the operator’s emergency plan, no external communications, no included imagery, and no mention of any mitigating or aggravating conditions aside from the obvious meteorological ones. The report is a succinct summary of the events that occurred, with very little coverage or indication of whether or not the investigation into root causes or any factors at play considered those beyond an engineering concern. In contrast, the 2020 TSB report for the Prince George 2018 incident is a 39 page document. It includes images from the site, detailed results of lab analysis and a broad view of both the cause and effects of the incident. Of particular interest, is the substantial analysis of Westcoast Energy’s integrity management program and the emergency management of the incident. The TSB report goes into great detail about the company's mitigation policies such as stress corrosion management practices and attempts to break down every detail of what went wrong that led to the failure. This example of root cause analysis shows a greater understanding of an applied risk management framework that is being increasingly promoted from within the oil and gas industry and beyond. Between 1997 and 2020 there has been significant changes to the agencies that regulate pipelines in British Columbia. For provincially regulated pipelines, the current authority (BCOGC) didn’t come into formation until 1998 and would have been in the early days of development during the Zyometz incident (2002). Likewise, the Canada Energy Regulator (CER) has gone through significant changes, transitioning from the National Energy Board in 2019 which involved a redistribution of responsibilities. The relationship and communications between these agencies, along with external (non-governmental) organizations such as the Canadian Energy Pipeline Association (CEPA), and other educational institutes and think tanks 137 has progressed over time. In conversations with both the BCOGC and CER, it was emphasized how often they work collaboratively on projects to promote pipeline safety, through information sharing and participation in working groups like those for stress-corrosion cracking. There is also an increase in sharing of resources; during the Westcoast Energy Inc incident in Prince George, the CER relied on BCOGC staff to respond initially in their place as their proximity allowed for a timelier presence on scene and made the response more efficient. Another noticeable change over time, demonstrated in the incidents is the level of communication between operators and regulators and the public. Over time, there has been an increasing public awareness of pipelines in BC, and consequently the public have become increasingly adamant in their rights to have information about pipeline operations and responses disclosed. In the wake of the EnCana sour gas incident there was a motion for a public inquiry to be held, signed by a large selection of locals and NGOs that are increasingly engaged in pipeline politics. Media coverage has also increased for each successive case that was studied. While in part this can be explained by the increased access to electronic media outlets, the increase in coverage also reflects a rise in public interest. For nearly every incident profiled, communication with the public and the community was cited as a weakness in the wake of a response, often for both the operator and the regulator. This has led regulators to work on new tactics, promoting communication, education, and pipeline ‘literacy’ in relevant communities throughout the province. The CER also recently introduced a requirement for their operators to publish their IMPs online, making them publicly available to anyone. These measures may both foster public confidence in pipeline operations as well as create a standard that operators will be held to in the event of an incident. In particular, the willingness of operators in particular to communicate natural gas pipeline information to the public will continue to be an avenue for development. 138 The examination of these five key incidents in the British Columbian natural gas pipeline landscape clearly show improvements to the technologies applied, management strategies, enforced regulations, and communication between industry, regulators and the public. However, they also show that there is still room for considerable improvement in the mitigation of human error, communication of company policies to employees, and in training. For companies to improve and prevent further incidents, there has to be a dissemination of lessons learned from prior incidents that must trickle down all the way to the operator. Continued communication between industry, regulators, and any independent research institutes or universities is essential to synthesise scientific discoveries with practical experience and create policies that will continue to improve the safety of pipeline infrastructure in the province. 139 Chapter 5: Conclusions and Recommendations 5.1 Challenges and Future Study While there has been considerable improvement in the safe operations of pipelines in BC over time and impressive increases in the emphasis placed on risk analysis, organizational learning, and cross industry communication and accountability, there remain challenges. The massive increase in the availability of data, both through technological storage solutions and collection methods, has been a boon to industry learning and development. However, the wholesale collection of more and more data does not come without challenges. Both through my own research, and in discussion with regulators it became readily apparent that the pipeline industry within Canada has very little standardization over data collection, storage, and use. There is no central storage of all pipeline data, rather data sets are created and stored through individual jurisdictions. To further challenge analysis, there are also no standards on reporting methodologies for pipeline incidents; the same root causes may be reported differently, or not at all depending on where thresholds are set. This was highlighted as a key issue by the CER during focus group discussions. From their perspective, even as the federal regulator, it is difficult to push for standardization where each jurisdiction has a specific way of collecting and storing information that may be valid to that region or be based on unique needs. Another challenge from a national perspective is that not all jurisdictions will have the resources in funding or knowledge to maintain a sophisticated data management set up. The lack of standardization makes effective analysis of pipeline incidents in Canada challenging, and incredibly difficult to make direct comparisons province to province. Evolving perceptions of the role of regulators have 140 encouraged CER to focus more on data collection and allow for Academic Institutions to conduct analysis, which will hopefully lead to further data analysis in the future. Further geospatial analysis of pipeline incidents in BC and across Canada would be beneficial to further highlight any trends in incident types and locations throughout the province and to compare them to international standards. However, significant work will need to be done on gathering and aligning disparate datasets. This same issue also makes geospatial research into ecological consequences of incidents difficult. Part of the research for this thesis included looking into the geospatial data available on this subject and it was found that the base shapefiles for the linear pipelines that combined both federal and provincial lines in their completeness were not readily available. There is significant opportunity here for further study. Organizational learning across the industry also continues to face challenges. Government regulators such as the BCOGC as well as CER, while relatively small in terms of personnel, are geographically spread quite thin. Depending on where employees are located, they may be excluded unintentionally from some discussions. Government agencies also typically experience consistent turnover of staff, which can lead to a loss of institutional knowledge and previously learned lessons. During discussions with agency staff, it was suggested that while there are intelligence management systems in place, there may be a lack of ‘buy-in’ or even knowledge of the systems and are therefore underutilized. As with any industry, the most pervasive and difficult problem to manage remains at the end, people. 5.2 Conclusion This thesis answers four research questions that were chosen to explore the framework that makes up the natural gas pipeline industry of British Columbia and their capacity to learn over time from experience, a changing regulatory landscape, and from failures or incidents. What 141 are the respective roles and responsibilities of the agencies that regulate the pipeline industry? The rules and responsibilities of the different regulators and organizations under different jurisdictions have created a patchwork landscape that, from an external perspective, can appear disjointed and isolated. While there is some overlap, largely roles as outlined in the Acts that govern pipeline operations in the province, are distinct and predetermined by pipeline size and distribution, making it difficult to easily grasp where responsibilities lie. This thesis pulled together the agencies into one easily understood map that allowed for a deeper dive into the interrelation between agencies and industry bodies. This leads to the second question raised for this thesis: how do lifecycle regulators at two different levels of government coordinate, share knowledge, and work together at an inter and intra jurisdictional level? It is evident from this work that there is effective and ongoing communication, cooperation, and inter-agency transparency in the work that is being done to promote the safe operation of pipelines in the province of British Columbia. From the work done with focus groups for this thesis, it is readily apparent that there are both the mechanisms, official and unofficial, as well as the desire to work across agencies and to support fellow regulators by sharing useful information and lessons learned. The formal agreements set up between regulators and other agencies such as MOUs are solid examples of the intent to share information, resources, and capacity. Further developments can be expected in this way, including the incorporation of Indigenous Nations into the regulatory and operational network. Another question raised for this research was what changes are made by agencies, and industry, after an incident? Incidents result in changes to the natural gas pipeline industry in BC, both in internally and in the realm of public perception. Pipeline incidents invariably bring together members of the industry from all sides together at once, creating an environment that 142 fosters a great amount of communication. The retrospective investigations into the causes of a failure highlight issues that can be searched for in other areas, used to identify trends and mitigate against further incidents. Analysis of incident reports for the case studies in this thesis have clearly demonstrated, that over time and successive incidents the standards for investigation into failures has become significantly more rigorous and detailed. These findings are demonstratively adopted into the monitoring and maintenance requirements put on industry. Repetitive causes of failure, such as stress corrosion cracking (SCC) have driven national inquiries that brought together government, industry, and scientists and re-wrote national pipeline operation guidelines. The final research question to be determined in this work was can the lifecycle regulators be considered learning organizations? Agencies are adapting to the increasingly reduced societal risk tolerances for industry and promoting transparency with the public through increased access to information. But there remain challenges in this realm. With the different jurisdictions, come disparate data sets that are often difficult to compare for research. In response, industry and government are increasingly turning to academic partners and other research organizations with the intent to provide information and data that can lead to further research and analysis beyond the scope of the regulators immediate responsibilities, such as the work being done by UBC’s Pipeline Integrity Institute. In discussions with the agencies, representatives were forthright and willing to discuss both the planned improvements within their organization as well as the challenges that still stand before them. One improvement has been the restructuring of agencies such as the Canada Energy Regulator which has, by their own account, made the industry more responsive to issues, stakeholders, and communities then before. 143 The ability to adopt new information and have it guide operations shows that agencies are determined to succeed as learning organizations. This means that knowledge is retained, incorporated, and transmitted throughout the organization. There remain challenges for companies to truly be considered learning organizations. Having jurisdiction over large areas with limited staff remains a protracted issue for natural resource agencies in Canada. There is also the inevitable turnover of staff who can depart with years or even decades of experience, knowledge, and project ownership that is challenging to capture for the benefit of the greater organization. These difficulties make the reports and published findings that result from incidents all the more important for encouraging permanent change. They represent lessons that can be reviewed by future staff and used in training, incident planning, and response practice. In this way incidents continue to inform learning and the natural gas pipeline industry in British Columbia continues to evolve. 5.3 Recommendations In light of the experience and interactions experienced during the process of this research, there are three recommendations that could be put to government to promote the continued evolution of the pipeline industry in British Columbia. Continue to promote transparency and openness with both the public and academic and research facilities. This improves the public understanding of the role regulators play in an industry that is increasingly polarizing and more external research may provide increased clarity on emerging issues and challenges. 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What formal mechanisms exist to support and facilitate communication between the BC Oil and Gas Commission (Commission) and other agencies or organizations (industry or other) working (as reviewers, regulatory, other) in the pipeline sector? 1.1 These can be ongoing (e.g. the deputy ministers group) or ad hoc (a working group that examines an issue, workshops, joint fact finding group, others). 2. Are there examples of informal mechanisms that can be described? For example, a ‘heads up note’ about the release of a pending report, or seeking input or ideas about how to use a research budget, data sharing, others. 3. Are there examples of where the Commission has shared resources (budget, people, data) with another agency working in the sector to meet a common need or even help out with the specific needs of another agency? For Q 4 onward… Introduce idea of organizational learning (from a business perspective, not academic) 4. We profiled 5 pipeline events that occurred in B.C. One of the aspects we would like to get a sense of is how the information and knowledge that comes from a review or investigation of such events are used by the Commission with respect to its own operations? 4.1 Follow up, if needed: Is there a formal learning process in place? 5. Has the Commission identified specific challenges or needs with respect to organizational learning? 172 6. Over the last 3 decades, it is fair to say that we have seen continual engineering, regulatory and assessment improvements in the pipeline sector, from the perspective of the Commission what have been the key innovations that your agency has implemented? 7. Are there innovations that other agencies or organizations (e.g. industry organization, research entities, others) have implemented that the Commission would describe as noteworthy (e.g. have had a transformational impact on the pipeline sector)
Thesis/Dissertation
eng
Earth and Environmental Sciences
Vancouver : University of British Columbia Library
Attribution-NonCommercial-NoDerivatives 4.0 International
Graduate
Hanna, Kevin S. (Kevin Stuart), 1961-
A longitudinal study of the natural gas pipeline industry in British Columbia
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