Assessment of the Threat From Wildfires on Above Ground Natural Gas Facilities

In the light of recent experience of wildfires in Alberta and British Columbia, Alliance Pipeline has strengthened their emergency preparedness in dealing with external fire events that have the potential to affect above-ground facilities connected with their high pressure natural gas pipeline system. As part of this initiative a quantitative methodology has been developed that enables the effects of a wildfire on an above-ground pipeline facility to be assessed. The methodology consists of three linked calculations which assess: 1. the severity of the wildfire, based on information from the Canadian Wildland Fire Information System, 2. the transmission of thermal radiation from the wildfire to the facility, and, 3. the response of equipment, structures and buildings to the incident thermal radiation. The predictions of the methodology agree well with the actual damage observed at a lateral block valve site following a wildfire in 2016. Application to example facility types (block valve sites, meter stations and compressor stations) has demonstrated that, in general, damage is only predicted for more vulnerable items such as cables. The sensitivity of the predictions of the methodology to the input parameters and key modelling uncertainties has been examined. This demonstrates that the results are sensitive to the distance of the facility from the tree line and the assumed vegetation type. This shows the importance of verifying the location relative to the vegetation and selecting the appropriate vegetation type from the Canadian Wildland Fire Information System for site specific assessments. The predictions of the methodology are particularly sensitive to the assumed flame temperature. However, a value has been chosen that gives good agreement with measured thermal radiation values from wildfires. Of the mitigation options considered, the most effective and practical is to increase the distance to the tree line. This measure has the advantage of reducing radiation levels for all items on the site. Even though the work shows that failure of exposed pipework due to wildfires is unlikely, maintaining the flow within pipes is recommended as this increases the radiative flux at which failure is predicted to occur. However, as failure of cables and hence control systems would occur at a lower flux levels the fail-safe actions of such systems needs to be confirmed. Shielding of cables or items of equipment in general is likely to be impractical but could be considered for particularly vulnerable equipment or locations.

Semi-Quantitative Reliability-Based Ranking Method for Assessment of Pipeline Dents With Stress Risers

Current regulations for prediction and management of potential delayed failures from existing pipeline dents rely primarily on depth and conservative assumptions related to threat interactions, which have shown limited correlation with industry failures. Such miscorrelation can lead to challenges in managing effectiveness and efficiency of pipeline integrity programs. Leading integrity techniques that entail detailed assessment of complex dent features rely on the use of finite element analysis, which tends to be inefficient for managing large pipeline systems due to prohibitively complex modeling and analysis procedures. While efforts are underway to improve dent assessment models across the industry, these often require significant detailed information that might not be available to operators; moreover, they suffer scattered model error which makes them susceptible to unclear levels of conservatism (or non-conservatism). Nevertheless, most techniques/models are deterministic in nature and neglect the effect of both aleatory and epistemic uncertainties. Operators typically utilize conservative assumptions based on subject matter experts’ opinions when planning mitigation programs in order to account for different types of uncertainties associated with the problem. This leads to inefficient dig programs (associated with significant costs) while potentially leaving dents on the pipeline which cannot be quantitatively risk assessed using current approaches. To address these concerns, the problem calls for a dent assessment framework that balances accuracy with the ability to assess dent and threat integration features at a system-wide level with available information in a practical timeframe that aligns with other integrity programs. This paper expands upon the authors’ previously published work regarding a fully quantitative reliability-based methodology for the assessment of dents interacting with stress risers. The proposed semi-quantitative reliability model leverages a strain-based limit state for plain dents (including uncertainty) with semi-quantitative factors used to account for complex geometry, stress riser interactions, and operating conditions. These factors are calibrated to reliability results from more detailed analysis and/or field findings in order to provide a simple, conservative, analytical-based ranking tool which can be used to identify features that may require more detailed assessment prior to mitigation. Initial validation results are provided alongside areas for continued development. The proposed model provides sufficient flexibility to allow it to be tailored/calibrated to reflect specific operator’s experience. The model allows for a consistent analysis of all types of dent features in a pipeline system in a short period of time to support prioritization of features while providing a base-level likelihood assessment to support calculation of risk. This novel development supports a dent management framework which includes multiple levels of analysis, using both deterministic and probabilistic techniques, to manage the threat of dents associated with stress risers across a pipeline system.

Are Pipelines Being Held to an Unreasonably High Standard of Performance?

The media and sections of the public have shown recently an acute interest in Pipeline operational performance incident statistics. Published data for North America shows that 99.999% of crude oil and petroleum products shipped by pipelines reach their destination safely. Some pipeline operators claim even better performance, 99.9996 % being one example. However, should failing to deliver 4 barrels of product for every million shipped be a legitimate cause for concern? If not how about the more general case of 1 per one hundred thousand? Is pipeline performance being singled out unreasonably when compared to other threats to public and environmental wellbeing such as medical malpractice or industrial waste contamination? Evidence from Canada and elsewhere, indicates that, during their hospital stay, an appreciable number of patients, one in every 18, experience adverse events, such as medication error, injurious falls, infections, and other medical misadventures. Errors (mostly minor), in fulfilling pharmaceutical prescriptions show an even higher error rate — 1 in 4 in one recent study, yet the public appears to be unperturbed. A common thread is determining what constitutes an acceptable level of risk whether individual or societal, voluntary or involuntary. Besides providing a broader context for pipeline risk, the paper explores the origin and intent of the environmental screening standard of 1 in 10−6, as well as the concept of setting risk tolerance to be as low as reasonably practicable — ALARP. The question of why there may be a reticence for many Pipeline Regulators to set, as other industries have, a prescriptive value for ALARP is considered.

CSA Z663: Land Use Planning in the Vicinity of Pipelines

There are few standards or regulations to help stakeholders consider land use and development in the vicinity of existing pipeline systems. Land use planning that considers the existence of pipeline systems can support the planning for and provision of emergency services and pipeline integrity. This approach can also promote public safety and awareness through consistent and collaborative stakeholder engagement early in the land use planning process. In 2016, a CSA workshop was held with a variety of stakeholders impacted by land use planning around pipeline systems. The workshop identified that there was a need for consistency across the jurisdictions in the form of a national standard. The main goal of the new CSA Z663 standard is to provide guidance and best practices for land use planning and development. It also addresses roles, responsibilities and engagement of all stakeholders to help establish a consistent approach to land use planning. A review of CSA Z663 will illustrate how this document provides information, guidance and tools that are inclusive to all stakeholders. This paper will also highlight the history and key drivers behind the new CSA Z663 standard and provide an overview of the current scope and content. Finally, the paper will describe future considerations and additions to the standard.

Risk Assessment for Small Diameter Piping for Liquid Pipeline Facilities

The Enbridge Liquids Pipeline system is comprised of a large number of facilities including storage terminals, pump stations, injection sites, and delivery sites. Given the vast amount of small diameter piping (SDP) within company Pipeline facilities, SDP represents a significant portion of total facility integrity risk. An event such as equipment failure or product release can cause significant business impacts, and adverse consequences to the environment and/or safety of operations personnel. A quantitative risk based approach is required in order to establish robust, risk-based plans and programs to maintain the integrity of these SDP sections. Small diameter piping lengths are relatively short. Consequently, it is impractical to use SDP length as a unit of likelihood and risk measure. Instead, the preferred methodology is to determine the total number of assemblies for each type of SDP. In support of this approach, an inventory of SDP sections throughout the system has been gathered. For illustrative purposes, an example of a small diameter section would be a pressure transmitter branch connection. The isolatable section that would be risk assessed would start from the surface of the main station piping connection and continue up to the transmitter. This paper presents the framework for likelihood and consequence assessment of SDP based on the system description above. This framework quantitatively estimates the risk of SDP failure and risk-ranks SDP sections in support of implementing and establishing a system wide Risk Based Inspection and Maintenance program for SDP.

Implementing API RP 1173, Pipeline Safety Management Systems: Tools and Resources to Facilitate Industry Implementation

Since the publication of API Recommended Practice (RP) 1173: Pipeline Safety Management Systems, in July 2015, the energy pipeline trade groups in North America (API, AOPL, AGA, INGAA, APGA and CEPA) have worked collaboratively to develop tools and programs to assist energy pipeline operators with the development and implementation of appropriate programs and processes. These resources include a Planning Tool, Implementation Tool and Evaluation Tool, as well as a Maturity Model that describes a continuum of implementation levels. The Planning Tool is used to compare an operator’s existing management system to the RP requirements and develop action plans and assign responsibilities to close gaps. It is intended to help operators achieve Level 1 maturity (develop a plan and begin work). The Implementation Tool is used to evaluate and summarize implementation status by question, element and overall, and helps track development of program implementation to Level 3 maturity. The Evaluation Tool plays two key roles addressing the conformity and effectiveness of the system. This tool is used to assess and report the level of conformity to the requirements, the “shall” statements, of the RP and possible Level 4 maturity. The Evaluation Tool also provides the means to appraise the effectiveness of an operator’s programs in achieving the objectives of the RP, asking the key question, “Is the system helping and driving improvement?” These resources can be supplemented by the voluntary third-party audit program developed by API and the Peer-to-Peer sharing process.

Girth Weld Strength Matching Effect on Tensile Strain Capacity of Grade X70 High Strain Line Pipe

Recently high grade pipeline project have been planned in hostile environment like landslide in mountain area, liquefaction in reclaimed land or the frost heave in Polar Regions. Geohazards bring large scale ground deformation and effect on the varied pipeline to cause large deformation. Therefore, strain capacity is important for the pipeline and strain based design is also needed to keep gas transportation project in safe. High grade steel pipe for linepipe tends to have higher yield to tensile (Y/T) ratio and it has been investigated that the lower Y/T ratio of the material improves strain capacity in buckling and tensile limit state. In onshore pipeline project, pipe usually transported in 12 or 18m each and jointed in the field. Girth weld (GW) is indispensable so strength matching of girth weld towards pipe body is important. In this study strain capacity of Grade X70 high strain pipes with size of 36″ OD and 23mm WT was investigated with two types of experiments, which are full scale pipe bending tests and curved wide plate tests. The length of the specimen of full scale bending tests were approximately 8m and girth weld was made in the middle of joint length. A fixed internal pressure was applied during the bending test. Actual pipe situation in work was simulated and both circumferential and longitudinal stress occurred in this test. Test pipes were cut and welded, GTAW in first two layer and then finished by GMAW. In one pipe, YS-TS over-matching girth weld (OVM) joint was prepared considering the pipe body grade. For the other pipe, intentionally under-matching girth weld (UDM) joint was prepared. After the girth welding, elliptical EDM notch were installed in the GW HAZ as simulated weld defect. In both pipe bending tests, the buckling occurred in the pipe body at approximately 300mm apart from the GW and after that, deformation concentrated to buckling wrinkle. Test pipe breaking locations were different in the two tests. In OVM, tensile rupture occurred in pipe body on the backside of buckling wrinkle. In UDM, tensile rupture occurred from notch in the HAZ. In CWP test, breaking location was the HAZ notch. There were significant differences in CTOD growth in HAZ notch in these tests.

Earned Schedule and the Use of Schedule Execution Reporting Metrics

The traditional approach of managing project performance is with the use of Earned Value Management. There is a recent trend towards the expansion of traditional Earned Value Management practices to include the concept of Earned Schedule. Whereas Earned Value provides insight as to how the project is trending in relation to the plan by assessing cost and schedule variances, Earned Schedule focuses on the time element of schedule performance throughout the project execution phase. Earned Value, although very effective at providing visibility to cost performance, is not as transparent when it comes to schedule performance over time. Case in point, at completion, irrespective as to how work progressed on the schedule (ahead or behind plan) at completion, the schedule performance index will always be 1.0. Earned Schedule overcomes this drawback, providing useful tools to report on schedule performance, and providing visibility to the project state from which to base informed decisions. To perform the analysis, Earned Schedule analysis incorporates detail from the baseline and forecast schedules as well as the integrated project management cost report (earned versus planned). In addition to looking at Earned Schedule metrics, other key metrics are factored into this approach to assess overall schedule performance. Key metrics derived from the schedule and highlighted in this approach include: • Critical Path Length Index (CPLI) • Baseline Execution Index (BEI) • Total Float Consumption Index (TFCI) • To Complete Schedule Performance Index (TSPI) • Predicted Forecast Finish Date (PFFD) • Schedule Performance Index (time) (SPIt) • Independent Estimate At Complete (time) (IEACt) The intent of these metrics is to identify trends and assist in predicting project outcomes based on past performance. Since this approach is highly dependent on the schedule data, the more compliant a schedule is to industry best practices the better the quality of the results. The metrics are negatively impacted by recent re-baselining as this causes us to lose historical performance detail. Frequent analysis of the schedule execution reporting metrics defined above provides transparency of project performance and brings visibility to early risk triggers in support of a proactive approach to project execution monitoring and control. This paper will present a case study demonstrating how additional transparency through this approach highlighted a potential schedule risk. This increased visibility allowed the project team to reprioritize and implement proactive corrective actions to mitigate any potential impact to the project In Service Date (ISD).

A Canadian Operator Based Framework for Pipeline Pressure Tests: Lessons Learned

Commissioning pressure tests are a critical life-of-asset record. Successfully achieving an acceptable pressure test can be challenging both at an execution and documentation perspective. This paper aims to assist in streamlining the approach to pipeline commissioning pressure tests between operators to increase efficiency and drive consistency across the pipeline industry. Key lessons learned from the planning stages through to the quality control turnover are highlighted. Lessons learned, respective to pressure tests, include: road map of Canadian regulations, tabulated equipment requirements, suggested instrumentation setup, template checklist for test plans, outlined company to contractor responsibilities, as well as a proposed internal process to manage and accept completed tests.

Management System Competency Model and Development Program

The pipeline industry continues to look for ways to improve its compliance and performance. Management systems have increased prevalence in the pipeline industry, with recognition that carefully designed and well-implemented management systems are the fundamental method that should be used to keep people safe, protect the environment and align organizational activities. Experience has shown significantly better success rates with management system implementation, both in terms of the quality and speed, when the person responsible for the design, implementation and sustainment of the management system has an integrated set of technical and enabling competencies. However, there is currently no standardized competency model that can be used to support a Management Systems Professional’s specialized knowledge and skills. The paper outlines the competencies needed by individuals to be effective in the design, implementation, measurement and evaluation of management systems. Applying a ‘whole-person’ perspective, the model includes business, relational and technical competencies that contribute to performance excellence for management system practitioners, including outlining example behaviours at target level performance and proficiency, and supported by a defined body of knowledge. This paper describes the Management System Competency Model, including how it can be used to create a position-specific development program for application within various organizations. This research establishes a basis for the creation of a practical, systematic and easy to use development road map for individuals and organizations who use or leverage a management system.