Pressure Cycling Monitoring Helps Ensure the Integrity of Energy Pipelines

Liquids pipelines undergo pressure cycling as part of normal operations. The source of these fluctuations can be complex, but can include line start-stop during normal pipeline operations, batch pigs by-passing pump stations, product injection or delivery, and unexpected line shut-down events. One of the factors that govern potential growth of flaws by pressure cycle induced fatigue is operational pressure cycles. The severity of these pressure cycles can affect both the need and timing for an integrity assessment. A Pressure Cycling Monitoring (PCM) program was initiated at Enbridge Pipelines Inc. (Enbridge) to monitor the Pressure Cycling Severity (PCS) change with time during line operations. The PCM program has many purposes, but primary focus is to ensure the continued validity of the integrity assessment interval and for early identification of notable changes in operations resulting in fatigue damage. In conducting the PCM program, an estimated fatigue life based on one month or one quarter period of operations is plotted on the PCM graph. The estimated fatigue life is obtained by conducting fatigue analysis using Paris Law equation, a flaw with dimensions proportional to the pipe wall thickness and the outer diameter, and the operating pressure data queried from Enbridge SCADA system. This standardized estimated fatigue life calculation is a measure of the PCS. Trends in PCS overtime can potentially indicate the crack threat susceptibility the integrity assessment interval should be updated. Two examples observed on pipeline segments within Enbridge pipeline system are provided that show the PCS change over time. Conclusions are drawn for the PCM program thereafter.

A Review of Crack Detection In-Line Inspection Case Studies

This paper describes case studies involving crack detection in-line inspections and fitness for service assessments that were performed based on the inspection data. The assessments were used to evaluate the immediate integrity of the pipeline based on the reported features and the long-term integrity of the pipeline based on excavation data and probabilistic SCC and fatigue crack growth simulations. Two different case studies are analyzed, which illustrate how the data from an ultrasonic crack tool inspection was used to assess threats such as low frequency electrical resistance weld seam defects and stress corrosion cracking. Specific issues, such as probability of detection/identification and the length/depth accuracy of the tool, were evaluated to determine the suitability of the tool to accurately classify and size different types of defects. The long term assessment is based on the Monte Carlo method [1], where the material properties, pipeline details, crack growth parameters, and feature dimensions are randomly selected from certain specified probability distributions to determine the probability of failure versus time for the pipeline segment. The distributions of unreported crack-related features from the excavation program are used to distribute unreported features along the pipeline. Simulated crack growth by fatigue, SCC, or a combination of the two is performed until failure by either leak or rupture is predicted. The probability of failure calculation is performed through a number of crack growth simulations for each of the reported and unreported features and tallying their respective remaining lives. The results of the probabilistic analysis were used to determine the most effective and economical means of remediation by identifying areas or crack mechanisms that contribute most to the probability of failure.

Inline Inspection: Both Effective Data Collection and Interpretation Needed to Achieve High Quality Reporting Results

Historically, pipeline operators have tended to place more weight on inline inspection tool specifications than on the inherent design and reporting capabilities of the service providers themselves. While internal collection of integrity data is very important, it’s imperative that vendors, also, have high levels of expertise and effective quality control systems in place to successfully analyze exceedingly high volumes of inspection data. The quality of inspection information is vital to assessing if a pipeline is fit for purpose now and/or into the future. Integrity managers attempting to reduce overall operating risk by making decisions based on inaccurate or poor quality reporting are in fact exposing their networks to greater safety and financial risk. Recognizing these risks and that inline inspection (ILI) is an overall system that needs to be formally qualified, operators and ILI service providers have collaborated to develop several international standards. The most recent is the umbrella API-1163 industry consensus standard, which is now being widely adopted, primarily in USA. This standard provides requirements and recommended practices for qualification of the entire ILI process. Two companion standards: ASNT In-line Personnel Qualification and Certification Standard No. ILI-PQ and NACE Recommended Practice In-Line Inspection of Pipelines RP0102 combine to address specific requirements for personnel who operate and analyze the results of ILI systems. In Europe, the Pipeline Operators Forum (POF) has, also, established specific requirements for ILI reporting processes and data formats. However, these standards do not define how operators and vendors must meet these requirements. To follow will be a story about how an ILI service provider embraced a holistic approach to address these standards’ requirements, in particular in the areas of data analysis, reporting, and dig verification due to their significant importance in assuring the final quality of its deliverables. A key outcome desired will be to provide operators with greater insight into what best practices and technologies ILI service providers should have embraced and invested in to insure reliable service delivery.

Fitness for Service Document Comparison: API 579 vs. PDAM

Assessing the Fitness for Service (FFS) of deficient pipeline segments or facilities is an important step in managing the mechanical integrity and safety of pipeline systems. However, FFS can be determined according to several documents, including API 579-1/ASME FFS-1 2007 Fitness-For-Service (API 579) and the Pipeline Defect Assessment Manual (PDAM). The document contents and assessment methodologies of API 579 and PDAM are reviewed and compared for several common damage mechanisms. API 579 was originally developed for the refining and petrochemical industries but is currently applied to a broad range of equipment and systems. In contrast, PDAM was developed under a joint industry project to assess defects specifically in petrochemical pipelines. While PDAM refers the reader to API 579 for the assessment of several damage mechanisms, including gouges, manufacturing defects, weld defects, and cracks, the authors of PDAM claim that API 579 is generic, biased towards pipes in process plants, and can be overly conservative for the assessment of other pipeline defects. Understanding and comparing the current FFS documents can lead to an enhanced allocation of available resources and can improve the level of FFS assessments in the pipeline industry. The methods used to assess corrosion of components with static internal pressures, dents, dent-gouge combinations, and cracks are compared.

Detection and In-Field Verification of Potential Pipeline Expansion Due to Low Yield Strength Pipe in High Strength Line Pipe

On May 21, 2009, the Pipeline & Hazardous Materials Safety Administration (PHMSA) issued an Advisory Bulletin (PHMSA-2009-0148) entitled, “Potential for Low and Variable Yield, Tensile Strength and Chemical Compositions in High Strength Line Pipe” [1] recommending that pipeline operators investigate whether recently constructed pipelines contain pipe joints not meeting the minimum specification requirements (74FR2390). Based on PHMSA’s technical reviews, high resolution deformation tool inspection combined with comprehensive infield verification has been recommended in accordance with the “Interim Guidelines for Confirming Pipe Strength in Pipe Susceptible to Low Yield Strength,” issued by PHMSA in September 2009[2]. Kern River Gas Transmission Company (Kern River) underwent a detailed program of engineering and assessment in order to proactively demonstrate compliance with the interim guidelines. This paper discusses the process, inspection results and infield verifications performed by the pipeline operator. In particular, detailed consideration to the methodology of detection and assessment of potential pipeline expansions is presented with discussion on the special considerations needed for low level anomaly identification, reporting and verification of expansions as defined in the PHMSA guidelines. High resolution caliper analysis approaches developed for this particular application are discussed and appropriate techniques are recommended that consider the effects of possible asymmetry of expansions and impact of other deformations such as ovality. Field verification practices and findings are reviewed in detail with particular focus on the challenges facing the pipeline operator in resolving both tool and in-field measurement errors that can significantly impact the number of identifiable candidate expansions for verification. In conclusion, an overview of the assessment criteria and field activity to comply with the PHMSA interim guidelines are presented along with the lessons learned from the analysis, verification and remediation steps that may assist other pipeline operators as they address these newly established regulatory requirements.

Remaining Local Buckling Resistance of Corroded Pipelines

This paper describes a multi-year PRCI research program that investigated the local buckling (or wrinkling) of onshore pipelines with metal-loss corrosion. The dependence of local buckling resistance on wall thickness suggests that metal-loss defects will considerably reduce such resistance. Due to the lack of experimental data, overly conservative assumptions such as a uniform wall thickness reduction over the entire pipe circumference based on the defect depth have been used in practice. The objective of this research work was to develop local buckling criteria for pipelines with corrosion defects. The work related to local buckling was carried out in three phases by C-FER and the University of Alberta. The first phase included a comprehensive finite element analysis to evaluate the influence of various corrosion defect features and to rank key parameters. Based on the outcome of Phase 1 work, a test matrix was developed and ten full-scale tests were carried out in Phase 2 to collect data for model verification. In Phase 3, over 150 parametric cases were analyzed using finite element models to develop assessment criteria for maximum moment and compressive strain limit. Each criterion includes a set of partial safety factors that were calibrated to meet target reliabilities selected based on recent research related to pipeline code development. The proposed criteria were applied to in-service pipeline examples with general corrosion features to estimate the remaining load-carrying capacity and to assess the conservatism of current practice.

Effects of Cathodic Protection on Cracking of High-Strength Pipeline Steels

A comparison was made between four strength levels of pipeline steels (X-70, X80, X-100 and the X-120) from the point of view of their susceptibility to hydrogen embrittlement under cathodic protection. The main aim was to determine whether the development of higher strength materials led to greater susceptibility to hydrogen embrittlement. This was achieved by straining at 2×10−6 s−1 after cathodic charging in a simulated dilute groundwater solution (NS4) containing 5% CO2/95% N2 (pH approximately 6.7). The results showed quantitatively the loss of ductility after charging, and the loss of ductility increases with strength level of the steel. All four steels exhibited a loss of ductility at overprotected charging potential and an increasing amount of brittleness on the fracture surface. Ductility in solution was measured under four different levels of cathodic protection, ranging from no cathodic protection to 500 mV of overprotection with respect to the usually accepted criterion of −850 mV vs. Cu/CuSO4 reference electrode. Experiments were carried out by straining during cathodic polarization in a simulated dilute ground water solution (NS-4 solution). Strain rates used were 2×10−6 s−1. After failure, the fracture surfaces were characterized by examination using scanning electron microscopy (SEM). Under cathodic protection, all four steels showed loss of ductility and features of brittle fracture. The loss of ductility under cathodic polarization was larger the greater the strength of the steel and the more active (i.e., more negative) the applied potential. The Ductility Reduction Index (DRI) was defined to quantify the reduction in ductility.

The Role of Electrochemical Conditions in Near-Neutral pH SCC Initiation Mechanism(s)

In order to improve our understanding of near-neutral pH SCC initiation mechanism(s), a comprehensive test setup was used to study the electrochemical conditions beneath the disbonded coatings in cracking environments. In this setup the synergistic effects of cyclic loading, coating disbondment, and cathodic protection were considered. Our previous results showed that there can be a significant variation in the pH of the localized environment under the disbonded coating of pipeline steel. The pH inside the disbondment can change significantly from near-neutral to high pH values, strongly depending on the level of cathodic protection and CO2 concentration. Both of these variables affected the electrochemical conditions on the steel surface and therefore the initiation mechanisms. This work highlights the role of electrochemical conditions in near-neutral pH SCC initiation mechanisms.

Growth of Surface-Type Stress Corrosion Cracks in Near-Neutral pH Environments Under Disbonded Coatings

Near-neutral pH stress corrosion cracking (NNPHSCC), which occurs when ground water penetrates under the pipe coating, causes longitudinal cracks to develop on the surface of pipelines. Such cracks grow over time and can ultimately lead to pipeline failure. NNPHSCC is currently managed by in-line inspection or hydrostatic testing for oil and gas pipelines respectively. These procedures are enormously expensive and have to be repeated at predetermined intervals. Re-inspection intervals are currently determined by empirical models, which have been found rather imprecise. A major flaw in currently applied models is that they assume that once a NNPHSCC crack is formed, it grows at a constant rate that is independent of pipeline operating variables and both pre- and in-service history of the pipeline material. This is not necessarily true as pipeline history, the nature of the service environment and operating factors, among several other factors, have a strong influence on the rate of NNPHSCC crack propagation. Most existing models also treat NNPHSCC cracks as long through thickness cracks rather than surface type cracks typically observed in the field. This research proposes to provide an empirical model that more accurately predicts the growth rate of near-neutral pH SCC cracks in near-neutral pH environments by studying the growth rate of surface type flaws while also accounting for the influence of operating factors, environmental factors, coating disbondment and cathodic protection on the rate of crack propagation. This paper reports some preliminary test results obtained using a long specimen with three semi elliptical surface flaws located in three reduced sections to simulate field observed NNPHSCC cracks. Preliminary results suggest that: 1) crack grows much faster at the open mouth, which was attributed to hydrogen effects; 2) crack dormancy can occur under certain combined mechanical factors; 3) although the benign mechanical loading cannot lead to a direct crack growth (crack dormancy), it causes damage to the crack tip, which makes the crack more susceptible to crack growth upon a more aggressive condition is encountered.

Guidelines to Conducting Threat Susceptibility and Identification Assessments of Pipelines Prior to Reactivation

This paper provides guidelines to identify all threats and assess a pipeline’s susceptibility to those threats in order to select appropriate and effective mitigation, monitoring, and prevention measures prior to reactivating pipelines. The intent of this paper is to provide pipeline operators, consultants and regulatory agencies with a generic threat assessment approach that has to be customized to the pipeline-specific characteristics and conditions, and the regulatory requirements of its own jurisdiction. A literature review and authors’ experiences across the pipeline industry have identified the need for a generic, yet complete approach that guides pipeline integrity engineers in the methodologies that adequately and effectively assess threats prior to reactivation and that can be validated in a timely manner during the operations. Pipeline operators may be called on to reactivate pipelines that are facing challenges such as aging, changes in operational conditions, lack of maintenance and inconsistent integrity practices while facing constraints from increasing population density, higher pressure and flow throughput requirements of a competitive marketplace, and regulatory requirements insisting on higher levels of safety and protection of the environment. This paper was structured with the following components to assist the reader in conducting threat assessments: • Current regulations and recognized industry standards with respect to reactivating pipelines; • Definition of and differentiation between hazard and threat; • Hazard identification analysis for the known and potential situations, events and conditions; and • Threat susceptibility and identification analysis process for the known categories derived from the hazard identification process. A case study is described as an example of applying the guidelines to conduct threat susceptibility and identification assessments of a pipeline prior to its reactivation. The results from the threat susceptibility and identification assessment process can help operators, consultants and regulators in determining effective inspection, mitigation, prevention and monitoring measures.