TransCanada PipeLines Limited Section 58 Application Iroquois Export Bi-Directional Modification Attachment 8. Engineering Assessment

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2 Pipe Integrity of Line APPROVALS Originator: Terry Huang, P.Eng. Risk & Engineering Strategy, Pipeline Integrity Original signed by Reviewer: Mohammad Al-Amin, P.Eng. Risk & Engineering Strategy, Pipeline Integrity Original signed by Accountable Manager / Approver: Shahani Kariyawasam, P.Eng. Risk & Engineering Strategy, Pipeline Integrity Original signed by Responsible Engineer: Terry Huang, P.Eng. Risk & Engineering Strategy, Pipeline Integrity Original signed by Page 1 of 21

3 Pipe Integrity of Line TABLE OF CONTENTS Page No. EXECUTIVE SUMMARY. 3 1 BACKGROUND AND PURPOSE OF ENGINEERING ASSESSMENT SCOPE DEFINITIONS Terms and Abbreviations DATA COLLECTION AND VALIDATION Pipeline System Description Operating and Maintenance History Expected Operating Conditions HAZARD IDENTIFICATION External Corrosion Internal Corrosion Stress Corrosion Cracking Weather and Outside Forces Mechanical Damage Manufacturing, Construction and Fabrication Incorrect Operations Equipment Malfunction Pressure Cycle Fatigue RISK MANAGEMENT METHODOLOGY CONCLUSIONS REFERENCES Regulations, Codes and Standards Industry Publications and References TransCanada Procedures and References Page 2 of 21

4 Pipe Integrity of Line EXECUTIVE SUMMARY This (EA) was conducted by TransCanada PipeLines Limited (TransCanada) to assess the integrity condition of the pipeline segments that will experience bi-directional operation once the proposed Iroquois Export Bi-directional Modification Project (the Project) is completed, and to determine what measures, if any, are required to maintain their safe operation under the new operating conditions. Modifications at the Iroquois Export Meter Station will allow for bi-directional flow on Line Iroquois Lateral. This additional operational flexibility will ensure continued reliable service to customers. The pipeline segments that will experience flow reversal are between Mainline Valve (MLV) 145A-2 and the connection point to the Iroquois Gas Transmission System (IGTS) at the United States international border on Line Iroquois Lateral. The maximum operating pressure (MOP) in these pipeline segments will remain unchanged with the flow reversal. The original design, material, construction, operating and maintenance history, and expected operating conditions of the assessed pipeline segments of Line were reviewed in this EA. All known pipeline integrity hazards for the segments on Line were considered and assessed in this EA. The operating and maintenance history of the pipelines showed that no in-service failure has occurred on these pipeline segments. TransCanada manages these pipeline integrity hazards according to its integrity management program (IMP). Based on the hazard identification and risk assessment performed in accordance with TransCanada s IMP, it was determined that the risk associated with all the known pipeline hazards in the bi-directional flow condition can be maintained at a low risk level. Therefore, no modification to the established IMP is required. Nevertheless, TransCanada will perform the following activities over and above the application of its existing IMP to address the potential effects of bi-directional operation on Line : Complete fatigue analysis for Line after one year of bi-directional operation if the number of pressure cycles due to flow reversal are significantly above the maximum expected thirty cycles per year, or if other operating conditions are different from what was assumed in this EA; Update the construction records and maps to reflect the facility modifications performed to reverse the flow in the affected pipeline segments; Review and update the operations and maintenance procedures before flow reversal, and ensure employees and contractors acknowledge the changes in procedures and follow the updated procedures to account for bi-directional operation; and Continually assess, monitor and manage the integrity hazards of the pipeline under the new operating condition according to TransCanada s procedures. Page 3 of 21

5 Pipe Integrity of Line BACKGROUND AND PURPOSE OF ENGINEERING ASSESSMENT The Iroquois Export Bi-directional Modification Project (the Project) proposes modifications to the Iroquois Export Meter Station on TransCanada s Canadian Mainline System. The purpose of the proposed modification is to allow for delivery of gas through Line from both the Canadian Mainline to the Iroquois Gas Transmission System (IGTS) in the United States (US) (i.e., southbound flow), and from IGTS in the US to the Canadian Mainline (i.e. northbound flow). Currently, Line receives gas from the Canadian Mainline at Station 1401 (Iroquois Compressor Station) where the Iroquois Export Meter Station is co-located, and flows gas southbound to supply gas to IGTS in the US. The Project proposes modifications to the Iroquois Export Meter Station to enable Line bi-directional flow. For the location of the pipeline segments and facilities that comprise the Project, see Figure 1. This figure also shows the current and proposed flow directions for Line TransCanada completed an EA to assess the integrity of the existing pipeline segments that will experience operational changes due to the proposed Project, and to determine what measures are required, if any, to maintain safe operation of these pipeline segments under the new operating condition (i.e., bi-directional flow). 2 SCOPE This EA applies to the pipeline segments of Line between its tie-over to the Canadian Mainline at the MLV 145A-2 site (hereinafter referred to as MLV 145A-2) and the connection point to IGTS at the US border. These pipeline segments are hereinafter referred to as the affected segments. Page 4 of 21

6 Pipe Integrity of Line Figure 1: Location of Pipeline Segments and Facilities and the Expected Flow Direction in Line Iroquois Lateral Page 5 of 21

7 Pipe Integrity of Line DEFINITIONS 3.1 Terms and Abbreviations For the terms and abbreviations used in this EA, see Table 1. Term Affected segments CIS DCVG (EA) Table 1: Terms and Abbreviations Definition The segments of pipeline that will be reversed, or be capable of bi-directional flow. Close Interval Survey Direct Current Voltage Gradient A documented assessment of the effect of relevant variables on fitness-for-service or integrity of a pipeline system. The assessment uses engineering and risk management principles conducted by, or under the direct supervision of, a competent person with demonstrated understanding and experience in these principles and related to the issue being assessed. FBE Maximum operating pressure (MOP) MLV OD Practice of Engineering (POE) POF R-ratio SMYS Fusion Bond Epoxy The maximum pressure at which a pipeline, or segment of a pipeline, may be operated, as per the appropriate code or standard. Mainline Valve Outside Diameter An act of reporting on, advising on, composing, evaluating, designing, preparing plans and specifications for, or directing the construction, technical inspection, maintenance or operation of any structure, work or process. It involves applying engineering principles and safeguarding life, health, property, the environment and public welfare. Probability of Failure Ratio between the minimum and maximum pressure of a pressure cycle determined by the rainflow counting method. Specified Minimum Yield Strength Page 6 of 21

8 Pipe Integrity of Line DATA COLLECTION AND VALIDATION 4.1 Pipeline System Description Line was constructed in 1991 with minor modifications in 1996 and The 1996 modification was to tie Line over to Canadian Mainline Line at MLV 145A-2 and the 1998 modification includes the additions of a 2.41 m tee assembly that connects to the crossover to Line and a 6.25 m valve assembly on the section between the meter inlet and outlet of Iroquois Export Meter Station at Station The 4.4 km long NPS 30 Line was built using line-pipe manufactured by Stelco. Fusion Bond Epoxy (FBE) was used as the external coating for the majority of the pipeline segments and a relatively small length of the pipeline segments is coated with polyurethane coating. For the line-pipe properties of Line between MLV 145A-2 and the connection point to IGTS at the US border, see Table 2. Table 2: Line Pipe Properties between MLV 145A-2 and Border Connection Point to IGTS Line Outside Diameter (mm) MOP (kpa) Wall Thickness (mm) Manufacturer External Coating Grade (MPa) %SMYS (%) Construction Year Total Length (m) Stelco FBE Stelco FBE Stelco Polyurethane Stelco FBE or Polyurethane The record of the commissioning hydrostatic test profile shows that the entire Line was divided into 8 test sections to perform the hydrostatic pressure tests. All the sections were designed for Class Location 3 using a design factor of 0.5 as defined in CSA Z184-M86 and were pressure tested to meet the Class 3 location requirement specified by CSA Z184-M Operating and Maintenance History As part of the EA, the following information was considered and used to identify and assess the integrity hazards for the affected segments: Operating Pressure Service History Cathodic Protection (CP) Surveys Inspection Records Gas Quality Data Excavation Results Relevant Incident and Issue Tracking Numbers 4.3 Expected Operating Conditions The historical and expected future operating condition of Line was reviewed to understand the expected change in operating conditions of this pipeline. Bi-directional operation is expected, with gas shipped according to market requirements. Page 7 of 21

9 Pipe Integrity of Line The pressure data for the subject pipelines were reviewed in this EA. The comparison between the historical operating pressure range and predicted future operating pressure range is shown in Table 3 below. The Iroquois Export Meter Station is located at the suction side of Station 1401 and it has an historical operating pressure range of 4600 kpa to 6600 kpa and similarly, the operating pressure on the discharge side of Station 1401 had a range of 5000 kpa to 9929 kpa. After the proposed operational change, for the southward flow, the operational pressure ranges are expected to remain the same. Following the operational change to enable northward flow, the operating pressures are not expected to be significantly different, as shown in Table 3. As part of the modification project, control valves will be installed at Station 1401 to provide pressure control for gas received from IGTS during the south-to-north operation. For the expected south-to-north operation, the compressor station will not be operated and the pressure at Iroquois Export Meter Station will be limited to 6450 kpa by the control valves to flow gas into Canadian Mainline. As the nearest IGTS compressor station to Line is about 117 km south, the operation of the nearest compressor station of IGTS will not have significant impact to the pressure fluctuation on Line during the south-to-north operation. It is expected that the flow will be reversed at maximum only thirty times per year. Therefore, the bi-directional operation will not significantly impact the fatigue life of the pipeline, as confirmed by the fatigue analysis (see Section 5.9). The historical and expected gas temperature data for Line was also reviewed. Following the operational change, it is not expected that there will be a significant increase in gas temperatures for both southward and northward flow. In addition, review of the wetland database revealed no significant length of organic soil in the pipeline ROW. Therefore, the likelihood of thermal expansion is low under the expected operating conditions. The operation of the Canadian Mainline and Line will remain the same after the completion of the Project. Table 3: Current and Expected Pressures in Line Pressure Measurement Point Iroquois Export M/S (Suction Side of Station 1401) MLV (Discharge Side of Station 1401) Pressure Range (kpa) Current north-tosouth operation Expected north-tosouth operation Expected south-tonorth operation HAZARD IDENTIFICATION This section describes the review of possible integrity hazards to the pipeline segments of the Project. Hazards were identified and assessed according to TransCanada s integrity process for the following hazards: External Corrosion Internal Corrosion Stress Corrosion Cracking Weather and Outside Forces Page 8 of 21

10 Pipe Integrity of Line Mechanical Damage Manufacturing, Construction and Fabrication Incorrect Operations Equipment Malfunction Pressure Cycle Fatigue The hazard identification and assessment process for each hazard is described in the following sections. 5.1 External Corrosion External corrosion is managed by implementing, operating and maintaining the Cathodic Protection (CP) systems on all pipelines, application of external coatings, and maintaining the pipeline condition using in-line inspection (ILI) and/or excavations. The susceptibility of a pipeline to external corrosion is determined by considering coating type, coating condition, pipe attributes, environmental conditions and effectiveness of CP. Metal loss ILI is used to detect and size corrosion anomalies on pipelines and assess the integrity of pipelines with regard to external corrosion. The performance history of the pipeline, coating type, CP survey, and assessment information were considered to assess the external corrosion hazard in this EA. Line has not experienced any in-service ruptures or leaks as a result of external corrosion. The majority of the pipeline in the affected pipeline segments is coated with high-performance coating (i.e., FBE). A total of m of line pipe is coated with polyurethane and a 15.2 m-long line-pipe segment is coated with FBE or polyurethane (see Table 2). Although the coating type used for the girth welds was not specified in the construction records, high-performance coating (e.g. epoxy urethane or liquid epoxy) was widely used for girth weld coating according to the Company s construction practices in 1990s. CP is continuously and effectively managed on the pipeline segments in accordance with TransCanada s CP criteria specifications, which adhere to CSA Z Clause 9.9, and Canadian Gas Association (CGA) recommended practice OCC The annual test lead CP survey data from 2011 to 2016 were reviewed to assess the historical performance of the CP system. The data showed no persistent sub-criteria pipe-to-electrolyte potentials, which is indicative of a CP system that is performing well and therefore minimizing the corrosion threat on the affected segments. The affected pipeline segments of Line have been inspected and re-inspected with a Magnetic Flux Leakage (MFL) and Caliper Combo ILI tool in 2009 and 2016, respectively, with a 7 year re-inspection interval. The most recent 2016 ILI data was reviewed and showed only one very minor external metal-loss feature (with a depth of 11% of wall thickness) was detected and reported by the high-resolution MFL tool. As a limited number of metal-loss corrosion features were reported by the 2016 MFL ILI for Line , the sizing accuracy of the MFL tool was validated using ILI data reported by the same MFL tool and same sizing algorithm from other pipelines. Figure 2 is the unity plot of feature depth for metal-loss corrosion features reported by the same MFL tool on other pipelines. The unity plot shows the measurement error of the MFL tool on feature depth is within the industryaccepted specification (i.e. +/-10% WT with 80% confidence level). Therefore, it is expected that Page 9 of 21

11 Pipe Integrity of Line the sizing accuracy of the 2016 ILI on Line using the same MFL tool is within the acceptable specification. Figure 2: Unity Plot of Feature Depth Data Gathered from Other ILIs Using Same MFL Tool The one external metal-loss corrosion feature reported by the 2016 MFL ILI on Line is managed under TransCanada s ILI Corrosion program which employs both a deterministic criterion, provided in CSA Z Clause 10.10, and a reliability based criterion as provided in TransCanada s TEP-INT-ILI-CDN Analysis of MFL In-Line Inspection for Canadian Pipelines procedure. A probabilistic growth analysis was performed on this feature. The analysis quantified all relevant uncertainties by using a probability distribution for each factor that contributes to calculating a corrosion defect s burst pressure. The relevant uncertainties included: the feature sizing uncertainty (i.e., tool measurement errors); growth rate uncertainty; material property uncertainty (e.g., yield/tensile strength); pipe geometric uncertainty (e.g., wall thickness and diameter); and, the burst pressure model uncertainty (i.e., model error). The growth analysis results showed that the feature will not exceed the reliability-based criterion before the next ILI re-inspection that is scheduled for As per TransCanada s TEP-ITM-ECOR External Corrosion Threat Management Program (CDN) procedure, the corrosion management program is constantly being reviewed and evaluated. The review of coating type, CP survey, and ILI assessment information showed that external corrosion does not pose an immediate threat to the affected pipeline segments. TransCanada will continue to manage the external corrosion hazard on the affected segments of Line according to TransCanada s external corrosion threat management procedure (TEP-ITM-ECOR). 5.2 Internal Corrosion Page 10 of 21

12 Pipe Integrity of Line Prevention of internal corrosion is achieved by monitoring and controlling corrosive substances in the gas flow. TransCanada adheres to its Transportation Tariff to ensure the quality of the gas product that enters the system. The performance history of pipeline, gas quality data, ILI results and historic excavation information were considered to evaluate the internal corrosion hazard. Line has not experienced any in-service ruptures or leaks as a result of internal corrosion. The Iroquois Export Meter Station has real time monitoring of the gas being exported to the US. The gas quality data at the Iroquois Export Meter Station was reviewed to assess gas quality history for the affected pipeline segments. The gas quality data include amounts of H2O, H2S, total sulphur and CO2 in the gas. There is no new gas entering the system here and a review of the available data shows no water off-specs associated with corrosive substance off-specs (H2S, CO2, O2) which greatly reduces the likelihood of internal corrosion occurring. No internal metal-loss corrosion feature was reported by the 2016 MFL ILI in the affected pipeline segments of Line The review of gas quality data, historical performance and ILI assessment information indicates that the likelihood of internal corrosion in the affected pipeline segments of Line is very low. The gas quality data will be continuously monitored and managed after the flow reversal for these pipeline segments. The gas quality requirements of the Canadian Mainline System Transportation Tariff are enforced at receipt points to ensure gas in the segments is dry and noncorrosive. TransCanada will continue to manage the internal corrosion hazards using ILI for the affected segments of Line as per TransCanada s internal corrosion threat management procedure (TEP-ITM-IC). 5.3 Stress Corrosion Cracking Stress corrosion cracking (SCC) is considered to be a time-dependent hazard, and is classified into two types near-neutral ph and high ph SCC. In accordance with TransCanada s Integrity Threat Management (ITM) procedure (TEP-ITM-SCC), pipe age, operating stress level and coating type information are considered in predicting the potential existence and severity of SCC. Line has not experienced any in-service ruptures or leaks as a result of SCC. Line is predominantly coated with FBE while a total of m of line pipe is coated with polyurethane. FBE is considered to be a high-performance coating because of its proven long-term durability and compatibility with CP systems for both high and near-neutral ph SCC. Based on 2009 and 2016 MFL ILIs, there was no evidence of corrosion that might indicate poor performance of the coating systems. Moreover, the maximum operating stress of Line (50% SMYS) is below the susceptible level of 60% SMYS. TransCanada s performance history of FBE and polyurethane coating systems have been excellent with no instances of SCC having been found where these coatings have been used. Therefore, given the experience with these coatings, the condition of coating on these pipeline segments, and the type of coating systems, the likelihood of SCC on Line is considered to be very low. As such, no integrity work is currently planned by the SCC Team for Line The pipeline will continue to be condition monitored on all integrity excavations, where the long seam, girth weld, and areas of corrosion / disbondment will be magnetic particle inspected to Page 11 of 21

13 Pipe Integrity of Line verify if any SCC is present. If any SCC is found in the digs, the SCC program for Line will be adjusted accordingly. The affected pipeline segments are expected to be operated within the pressure ranges that are very similar to the historical pressure ranges, as per Table 3, and it is not expected to have any significant pressure increase and associated change in % SMYS. Therefore, the flow reversal will have minimal impact on the SCC hazard for the affected pipeline segments. TransCanada will continue to monitor, assess and manage the SCC hazard on the affected pipeline segments as per TEP-ITM-SCC. 5.4 Weather and Outside Forces TransCanada developed its Weather and Outside Forces (WOF) management program to identify, assess, monitor and remediate issues resulting from WOF hazards. Hazards managed by the WOF management program include landslides, seismic hazards, fault planes, subsidence and heave, erosion and scour, and meteorological events. Hazard consideration is based on performance history and geotechnical assessment. Line has not experienced any in-service ruptures and leaks as a result of WOF. The pipeline is generally within flat terrain. There is one water crossing, and there are no slope locations that are being monitored. The review of WOF hazard for the affected pipeline segments of Line indicated that there are currently no known WOF hazards in these segments. As WOF hazards are related to external effects on pipelines, the flow reversal will not affect the likelihood or severity of these hazards. The potential WOF hazards on the affected segments will be managed by TransCanada s WOF ITM procedure (TEP-ITM-WOF). 5.5 Mechanical Damage Mechanical Damage considers the condition of the pipe wall and coating (e.g., dent, gouge, scrape, ovality, chip or scratch) where it is affected by mechanical or non-mechanical equipment including, but not limited to, excavators, agricultural equipment and hand operated tools. Prevention of Mechanical Damage is a goal of TransCanada s Damage Prevention Program. This program is directed at both internal and external stakeholders who plan to engage in ground disturbance related activities with the intent of ensuring understanding and adherence to ground disturbance regulations and safe excavation best practices with the overall goal of preventing mechanical damage occurrences. Any unauthorized activity, leaks, or other impacting conditions are reported in EHSM and acted upon. A review of historical unauthorized activity data has revealed no events of external interference occurring on Line Public awareness (PA), an integral component of the Damage Prevention Program, is designed to increase awareness of pipeline safety. Program engagement reaches the affected public, excavators and contractors, emergency responders and public officials, educating them about working and living safely near TransCanada facilities. The affected public were contacted in April, 2015 through the distribution of an awareness package, providing education and awareness about leak recognition and response, emergency preparedness and safe digging practices. Similar awareness material was distributed to excavators/contractors in May 2016 and will be distributed Page 12 of 21

14 Pipe Integrity of Line to Emergency Responders and Public Officials in the fourth quarter of In addition, the TransCanada calendar was mailed to landowners in September The last instrumented aerial patrols of Line were completed on September 12, 2016 and no indications of methane were detected. The last visual aerial patrol of Line was completed on January 9, There were no indications of missing signage and there were no indications of third party activity. The frequency of instrumented aerial patrol is 2/year and visual aerial patrol is 4/year. Line has not experienced any in-service failure caused by mechanical damage. The 2016 ILI caliper data showed no pipe wall deformation (top-side dent) that would be indicative of mechanical damage. As TransCanada has a program in place to prevent and monitor unauthorized activities, the likelihood of mechanical damage is considered to be low for the affected segments. Moreover, the likelihood of occurrence of mechanical damage is independent of the flow reversal. Mechanical damage hazard will continue to be managed by TEP-ITM-MECH. 5.6 Manufacturing, Construction and Fabrication Knowledge of manufacturing anomalies and the potential for their presence is based on TransCanada s operating history, and that of other industry pipelines that have similar properties. Prevention of such anomalies involves implementing manufacturing specifications that incorporate measures to ensure material quality and consistency, and adherence to standards. Line has not experienced any in-service ruptures or leaks due to manufacturing, construction and fabrication related hazards. Line was constructed in 1991 with pipes manufactured by Stelco. There have not been any failures in pipelines of similar vintage, attributes (i.e., OD, grade and wall thickness) and identical manufacture on TransCanada s Canadian Mainline. Furthermore, the pipeline was successfully hydrotested with a minimum test pressure of 1.40 times MOP to meet the Class 3 location requirement specified by CSA Z184-M86. Therefore, any remaining manufacturing flaws are stable under normal gas operation at the licensed MOP absent of interacting threats on the affected segments of Line Construction anomalies predominantly include girth-weld quality issues, contact and handling damage to pipeline coatings, and lowering and backfilling practices. For these known instances of construction anomalies, continual improvement in preventive and mitigative measures have resulted in practices being implemented to avoid causing such damage. According to TransCanada s construction specifications in 1991 and as indicated by the construction records, every weld on Line was required to be fully inspected using X-ray or ultrasonic techniques, and that any identified defects in the welds would have been repaired. Reversals of gas flow will not affect the likelihood or severity of construction defects as the change of flow direction under normal gas operation is unlikely to activate any remaining stable construction defects. The manufacturing, fabrication and construction threats are considered to be low and stable. TransCanada will continue to monitor ILI and excavation results on the line, and will incorporate the information into the threat identification process in accordance with TEP-ITM-MFC-CDN Manufacturing, Fabrication and Construction Threat Management Program. Page 13 of 21

15 Pipe Integrity of Line Incorrect Operations TransCanada views incorrect operation as a potential hazard on all the pipelines it operates. The potential for incorrect operation is managed by ensuring that personnel have received the appropriate training and development for their respective roles in the company. For example, TransCanada s Operations and Engineering personnel and contractors are required to complete training periodically to ensure awareness of and competence in policies and procedures, including all applicable TransCanada Operating Procedures (TOPs). Similarly, TransCanada s Gas Control team has a formal Gas Controller Development and Qualification program. This program includes initial qualification requirements for each operation console and annual re-qualification. TransCanada maintains a record of completion of learning requirements and evaluations in the corporate training application. Line has not experienced any in-service ruptures or leaks caused by incorrect operation. While TransCanada is confident in the strength and adequacy of its current procedures, it will review and, where appropriate, update its operations and maintenance procedures before implementing flow reversal on the affected segments. TransCanada will also ensure employees and contractors acknowledge the changes in procedures and follow the updated operational procedures to account for the bi-directional operation. Given these measures, the potential for incorrect operation is considered to be low for the affected segments. 5.8 Equipment Malfunction Equipment malfunction is a recognized hazard to the integrity and safety of all pipeline systems. TransCanada manages this hazard on Line by implementing its TransCanada Operating Management System. This management system underpins the development and implementation of integrity plans, facility maintenance plans and TOPs. The goals of this strategy are to: promote safety to TransCanada employees and contractors, the public and other stakeholders maintain service to customers maintain operations within acceptable tolerance levels Line has not experienced any in-service ruptures or leaks as a result of equipment malfunction or any other process. TransCanada will make necessary modifications, if needed, to the equipment at Station 1401 and the Iroquois Export Meter Station to allow for safe operation under the reversed flow condition. 5.9 Pressure Cycle Fatigue Line has not experienced an in-service leak or rupture due to pressure cycle fatigue. It is well established in the pipeline industry that pressure cycle fatigue cracking is not a significant contributor to gas pipeline failures under normal operating conditions. Typical gas pipeline pressure cycle spectra are far less aggressive compared to that of liquid pipelines (Kiefner and Rosenfeld 2004). However, TransCanada considers fatigue cracking as a hazard of concern for its gas pipelines operating outside of the typical gas pipeline spectrum, such as bidirectional pipelines subject to significant number of pressure reversals per year (Kiefner and Rosenfeld, 2004). Line pressure history data was analyzed to assess the risk of fatigue cracking. As mentioned in Section 5.3, pressure cycling after flow reversal and due to bidirectional operation is expected to be insignificant. Page 14 of 21

16 Pipe Integrity of Line TransCanada reviewed the pressure spectra from the discharge side of Station 1401 (MLV ), and the suction side of Station 1401 (Iroquois Export Meter Station) for Line The hourly average pressure history data for Line was obtained from the SCADA system, and is presented in Figure 3. Figure 3 shows that the section of Line at the suction side of Station 1401 (where Iroquois Export Meter Station is located) has been operating at pressures below the MOP, and the pressure fluctuations are low in amplitude. Rainflow counting analysis of the pressure spectra at the suction side of Station 1401 showed that the R-ratios of the pressure spectra range is between 0.7 and 1, which is a typical range for gas pipelines under normal operating conditions (Kiefner and Rosenfeld, 2004). According to Table 3, it is expected that this section of Line will continue to operate within similar pressure bounds and will be subject to similar pressure variations once the flow direction is changed. During a change in flow direction, the pressure will be limited to 6450 kpa on this section by the control valve, thus limiting the pressure effects during the flow reversal. Therefore, the flow reversal will have negligible impact to the fatigue life of this pipeline section. Figure 3 also shows that the section of Line at the discharge side of Station 1401 has been operating at pressures below the MOP. Rainflow counting analysis of the pressure spectra at the discharge side of Station 1401 showed the R-ratios of the pressure spectra range is between 0.5 and 1. During a change in flow direction, the maximum pressure fluctuation of this section is expected to range between 6895 kpa and 9929 kpa, which is equivalent to 30.6% MOP. It is conservative to assume that every instance of flow reversal will be associated with a full pressure cycle with the maximum pressure fluctuation. Adding the thirty full pressure cycles with the maximum pressure fluctuation due to flow reversal, the Rainflow counting analysis returned a relatively low equivalent number of annual cycles (54.7 cycles per year) corresponding to an equivalent pressure range of 30.6% MOP (i.e kpa). A fatigue analysis was performed to assess the minimum remaining fatigue life for this section of Line by assuming the fatigue cracking, if any that survived the commissioning hydrostatic test, could have maximum possible crack sizes that were equivalent to the minimum test pressure (140%MOP, i.e kpa) in Both API 579 FAD Level 2 and CorLAS (Beavers and Jaske 2001) crack assessment models were used in the fatigue analysis. The analysis results based on both of the models showed the calculated minimum remaining fatigue life for this section of Line was longer than 100 years. Based on the above analysis, the likelihood of fatigue cracking is considered low for Line The limited number of expected flow reversals will not significantly impact the fatigue life of the pipeline. However, TransCanada will update the fatigue analysis for the affected pipeline segments after one year of bi-directional pipeline operation if the number of flow reversals or the operating conditions are significantly different from the assumed conditions in this EA. Page 15 of 21

17 Pipe Integrity of Line Figure 3: Hourly Average Pressure Profile of Line between MLV 145A-2 and MLV RISK MANAGEMENT METHODOLOGY The risk to safety associated with a pipeline depends on both the likelihood and consequences of an undesirable event. Populated areas are recognized by TransCanada as areas of increased risk because a failure in these areas could potentially affect a significant number of people. As well, higher population densities could increase the likelihood of unauthorized activities, which could lead to pipeline failure due to mechanical damage. TransCanada uses two measures of risk for risk assessment, both of which are safety-related, since the primary danger associated with a pipeline rupture is accumulation of thermal radiation from the initial fireball and the subsequent jet fire. These two measures are the Individual Risk (IR) and the Societal Risk (SR). The definition of IR adopted by TransCanada is the risk to an individual that might be situated on top of the pipeline during a rupture. Furthermore, a conservative assumption of a person being on top of the pipeline 24/7 is adopted to protect any individual who might happen to be on the right-of-way. In addition to this exposure, the IR algorithm takes into account the lethality distance of the pipeline, which is dependent primarily on the diameter and operating pressure of the pipeline, and the probability of ignition. These factors are then combined with the probability of failure to calculate IR for each meter of the pipeline. Therefore, IR can be thought of as a baseline risk measure, regardless of whether there are structures near the pipelines. Page 16 of 21

18 Pipe Integrity of Line SR is a measure of risk to the known population, as indicated by structures and facilities for humans that are located in the lethality zone surrounding the pipeline. This measure of risk is location-specific, and explicitly considers the resident population. The criteria used to determine the maximum acceptable IR were adopted from Health and Safety Executive (HSE 2001), as shown in Figure 4, which stipulates that if the IR is below 10-4 fatalities/year and above 10-6 fatalities/year, it is considered tolerable if it is As-Low-As Reasonably Practical (ALARP). On the other hand, if it is above 10-4 fatalities/year, it is considered intolerable and must be mitigated. Finally, if IR is below 10-6 fatalities/year, it is considered tolerable. TransCanada s accepted SR risk acceptance criteria are shown in Figure 5. This criterion has been adopted from PD criteria (BSI British Standards 2009), and it stipulates that if SR is below the Tolerable line, it is considered widely acceptable. On the other hand, if SR is above the Intolerable Line, it is considered unacceptable and therefore must be remediated. When SR is between the two lines, it is tolerable if ALARP, implying that any measures that are practicable should be implemented to reduce the SR to widely acceptable levels. Reviewing the 2016 System-Wide Risk Assessment (SWRA) results for the 2017 risk assessment found the SR for the affected pipeline segments is below the bottom line of the PD criteria and it is considered Broadly Acceptable. Therefore, no mitigation is necessary. TransCanada performs SWRA annually. SWRA addresses all hazards and identifies segments that could reach IR and SR criteria and higher likelihood of failure for mitigation, as part of the Integrity Management Program. The SWRA 2016 results for the Project pipeline segments were reviewed in preparation of this EA. Figure 4: Individual Risk Criteria Based On HSE-Defined Criteria The IR and SR were determined by using the likelihood of failure values and, in the case of SR, it takes into account the structure data around the pipelines. The calculated IR and SR were then compared with the risk criteria, as discussed above. The comparison showed that the affected pipeline segments did not exceed the IR and SR criteria in As stated earlier in this section, TransCanada performs the SWRA annually on an ongoing basis to identify the high-risk segments, and plans integrity activities to mitigate the risk in the pipeline Page 17 of 21

19 Pipe Integrity of Line system. TransCanada will perform SWRA after Project completion and will subsequently mitigate any identified risk. Frequency of N or more fatalities 1.00E E E E E E E E E E-10 Intolerable ALARP Expected number of fatalities, N Figure 5: Societal Risk Acceptance Criteria Adapted from PD Standard Page 18 of 21

20 Pipe Integrity of Line CONCLUSIONS This EA was undertaken both to assess the integrity condition of the Line between MLV 145A-2 and the connection point to IGTS at the US border and to determine what measures, if any, are required to ensure safe operation of this pipeline under the proposed bi-directional flow conditions. The flow direction in these segments is expected to be reversed at maximum thirty times a year to meet market demand. The MOP of the affected segments will not be changed as a result of the proposed flow reversal and bi-directional operation. The original design, material, construction, operating and maintenance history, and expected operating conditions were reviewed for the affected segments of Line The effect of the flow reversals on the integrity of the pipelines was assessed. The operating and maintenance history of the pipelines showed that no in-service failure has occurred on the affected pipeline segments. All known pipeline hazards were considered and assessed for affected segments of Line It is concluded by this EA that the effect of the flow reversals on the integrity of the affected pipeline segments will be insignificant. As Line was assessed to have low or very low susceptibility to all the known pipeline hazards in consideration of the effect of the flow reversals, the pipeline is deemed to be fit for the purpose of bi-directional operation. TransCanada has procedures in place to actively manage the identified hazards. As stated in this EA, to maintain safe and reliable operation of the affected segments, the following activities will be performed: Complete fatigue analysis for Line after one year of bi-directional operation if the number of pressure cycles due to flow reversal are significantly above the maximum expected thirty cycles per year, or if other operating conditions are different from what was assumed in this EA; Update the construction records and maps to reflect the facility modifications performed to reverse the flow in the affected pipeline segments; Review and update the operations and maintenance procedures before flow reversal, and ensure employees and contractors acknowledge the changes in procedures and follow the updated procedures to account for bi-directional operation; and Continually assess, monitor and manage the integrity hazards of the pipeline under the new operating condition according to TransCanada s procedures. Page 19 of 21

21 Pipe Integrity of Line REFERENCES Regulations, Codes and Standards This EA was conducted in accordance with Clause 3.3 and Clause 10.1 of CSA-Z Industry Publications and References The industry publications and references that apply to this EA are: American Petroleum Institute Fitness-For-Purpose: API Recommended Practices 579. American Petroleum Institute. ASME B31.8S, Managing System Integrity of Gas Pipelines. American Society of Mechanical Engineers. Three Park Avenue, New York, NY. ASTM Standard E (2011). Standard Practices for Cycle Counting in Fatigue Analysis. ASTM International. West Conshohocken, PA. Beavers, J.A. and C.E. Jaske Integrity and Remaining Life of Line Pipe with Stress Corrosion Cracking. Pipeline Research Council International, Inc. Report No. PR BSI British Standards. 2009: Code of Practice for Pipelines Part 3: Steel Pipelines on Land Guide to the Application of Pipeline Risk Assessment to Proposed Developments in the Vicinity of Major Accident Hazard Pipelines Containing Flammables. Supplement to PD :2004. London, UK. Canadian Gas Association (CGA) OCC Control of External Corrosion on Buried or Submerged Metallic Piping Systems. Canadian Standards Association (CSA) CSA-Z184-M86 Gas Pipeline Systems Pipeline Systems and Materials. Health and Safety Executive (HSE). Reducing Risks, Protecting People: HSE s Decision Making Process Kiefner, J.F. and M.J. Rosenfeld Effects of Pressure Cycles on Gas Pipelines. Gas Research Institute Report No. GRI 04/0178. Rosenfeld, M.J. and J.F. Kiefner Basics of Metal Fatigue in Natural Gas Pipeline Systems-A Primer for Gas Pipeline Operators. Pipeline Research Council International, Inc. Report No. PR TransCanada Procedures and References The TransCanada procedures, guidelines, reports and documents that apply to this EA are: TEP-INT-DATA Pipe Integrity Data Management Program (CDN US MEX) (EDMS ) TEP-ITM-ECOR External Corrosion Threat Management Program (CDN) (EDMS ) TEP-ITM-EQUIP Equipment Threat Management Program (CDN US) (EDMS ) TEP-ITM-IC Internal Corrosion Threat Management Program (CDN-US) (EDMS ) Page 20 of 21

22 Pipe Integrity of Line TEP-ITM-IOPS Incorrect Operations Threat Management Program (CDN US) (EDMS ) TEP-ITM-MECH Mechanical Damage Threat Management Program (CDN) (EDMS ) TEP-ITM-MFC-CDN Manufacturing, Fabrication and Construction Threat Management Program (CDN) (EDMS ) TEP-ITM-SCC Stress Corrosion Cracking Threat Management Program (CDN US) (EDMS ) TEP-ITM-WOF Weather and Outside Forces Management Program (CDN US MEX) (EDMS ) Page 21 of 21