News and Views, Volume 54 | Structural Integrity Supports Pipeline Research Council International’s Hard Spot Project

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By Scott Riccardella and Steven Osgood

Structural Integrity is pleased to be working with PRCI to improve ILI performance, provide industry insight regarding prioritizing hard spots, and determine the optimal repair methodologies.

SI’s Pipeline Integrity Compliance Solutions (PICS) group has been implementing a highly strategic project from the Pipeline Research Council International (PRCI) focused on enhancing industry capabilities to detect and assess hard spot anomalies in gas transmission and hazardous liquid pipelines.

PRCI reviewed proposals from several highly qualified firms to support this project. Ultimately, SI was selected to provide support based on a combination of our expertise and integrated proposal, which demonstrated capabilities in field assessment, engineering analysis, and a reputation for providing synchronized follow-up. Being part of this PRCI project reinforces SI’s dedication to helping improve pipeline integrity and assessment practices and further position SI as an expert consulting partner for supporting pipeline operators’ fracture mechanics and in-line inspection (ILI) needs.

About the Project
Hard spots, or localized areas with elevated hardness within the pipe body, were believed to form during manufacturing. Hard spots are prevalent in piping produced by certain manufacturers and/or within certain vintages. They are believed to be attributed to inadequate quality control in the steelmaking, pipe-rolling, and welding processes. Over time, when in specific environmental conditions, cracking can initiate in the hard spots, creating a significant hazard. PRCI issued an RFP focused on evaluating and enhancing ILI tool technology and complementary analytical capabilities to reliably detect, size, and characterize the threat to integrity caused by hard spots.

Project Objective and Details
The project objective is to help the industry better understand ILI performance for more accurate detection and characterization of hard spots, providing targeted feedback, and developing insights to help improve ILI performance and prioritize ILI results.

ILI Performance Evaluation Study
The project’s main task is to evaluate the performance of various ILI technologies and service providers in identifying and characterizing hard spot defects. Testing is performed at the PRCI Technology Development Center (TDC) with pipeline samples (with various hard spot features) removed from service and configured in a test string for pull-through testing from several participating service providers. SI has characterized these samples using advanced NDE methodologies to establish reference data that will be used for determining the probability of detection (POD), probability of identification (POI), sizing accuracy, hardness estimation accuracy, and location accuracy. Individual performance reports will be provided as feedback to the participating ILI service providers to facilitate improving and advancing ILI technologies for hard spot detection and characterization.

Developing the Repair/Response Criteria
Following this testing, SI will complete additional analysis and modeling of the ILI Reported Values versus measured dimensions and hardness values for associated error. SI will also perform modeling to develop statistical correlations (with associated uncertainties) for estimating the Peak Hardness & Hard Spot Length from ILI Reported Values. Data will be analyzed in the context of historical failures and regulatory definitions of a hard spot. SI will develop an assessment methodology to evaluate hard spot criticality with a recommended response criterion (feature prioritization scheme) based on feature severity (length, hardness) and relative safety margin (Predicted Failure Pressure / MAOP).

“This project helps advance a critical initiative for PRCI, helping improve ILI capabilities to address a key threat to pipeline integrity. We are grateful to be partnering with Structural Integrity to develop and deploy this knowledge to our members.”

Jim Wayman – Program Manager Integrity and Inspection – PRCI

Evaluation & Recommendation of the Repair Methodology
SI is also working to complete research on different material properties and repair methodologies to determine the suitability of repairs. As part of this task, SI will complete a benchtop study using finite element analysis (FEA) to study the effectiveness of each repair approach (composites and Type A sleeves) leveraging the fitness for service (FFS) methodology detailed in the prior task (Repair/Response Criteria).

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News & Views, Volume 53 | An ECA Process for the Impact of Hydrogen Blending on Girth Weld Defects

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By:  Scott Riccardella, Owen Malinowski and Chris Tipple

Several pipeline operators have established pilot demonstration programs to blend hydrogen with natural gas (hydrogen blending) in their gas transmission pipelines.  Structural Integrity Associates (SI) has been providing clients technical consulting support to complete engineering critical assessment (ECA) projects to help evaluate the potential impact to pipeline integrity and help ensure the safety of the public, customers, employees, and the natural gas pipeline infrastructure. 

In a recent study, girth weld defects were identified as a key threat to pipeline integrity, particularly when the pipeline is exposed to large axial strain due to soil movement (which can be experienced from landslides, underwater erosion, storm surge, ground settlement and lateral spreading).  The impact to girth weld defects combined with large strain can pose a significant threat that is further exacerbated with hydrogen blending.  SI developed and implemented a program to complete a detailed ECA using probabilistic risk modeling to assess the probability of rupture (POR) to an offshore pipeline that had experienced significant strain due to erosion of the channel area, pipeline movement, and sand waves in the sea channel.  

To complete the ECA, a probabilistic analysis was performed consisting of the following activities:

REVIEW OF IN-LINE INSPECTION RESULTS

  • Recent strain data collected from an Inertial Mapping Unit (IMU) In-Line Inspection (ILI) tool were reviewed and analyzed to create a map of applicable strain at each girth weld in the study. 

MATERIAL PROPERTY, DEFECT AND OPERATING DATA ANALYSIS

  • Pipe populations were developed with specific characteristics that make them more compatible with hydrogen blending, or less compatible due to the respective susceptibility to hydrogen-related threats under different operating conditions.
  • SI developed Statistical distributions for key material properties (strength, toughness, wall thickness, etc.) and girth weld defect characteristics (length, depth, etc) using client specific and industry databases.
  • SI reviewed and incorporated relevant material tests performed to evaluate the effects of targeted hydrogen blend levels on the materials of interest (carbon steel base metal, longitudinal seam welds and girth welds).

DETERMINISTIC ANALYSIS USING FINITE ELEMENT MODELING (FEM)

  • A finite element analysis was utilized to determine the stress intensity factor of a circumferentially oriented crack subjected to high bending loads resulting in large axial strain.  The elastic-plastic analysis was used to determine the stress intensity factor as a function of strain, for a circumferentially oriented, externally breaking crack subject to a bending stress.

DEVELOPMENT OF A FRACTURE MECHANICS MODEL 9for probabilistic modeling)

  • From the FEA results a simplified elastic model was developed relating the stress intensity factor to the peak tensile axial strain resulting from bending.
  • SI incorporated the stress intensity factor from this model into an API 579 FAD based evaluation of girth weld, crack-like defects.

REVISIONS TO SI SYNTHESIS™ SOFTWARE

  • SI has developed specialized risk analysis software tools to evaluate pipeline POR which were applied to evaluate the impact or hydrogen blending to the POR. 
  • The software was specifically enhanced for this analysis to incorporate the following items:
    • Evaluation of flaws associated with circumferential cracking (such as those that may be encountered in vintage girth welds).
    • Incorporation of secondary loads and stresses (such as those encountered through land/soil movement).

PROBABILISTIC ANALYSIS

  • SI applied the probabilistic framework to evaluate the increased susceptibility to failure imposed from hydrogen blending with special consideration for ground movement and girth weld defects.  
  • This framework used Probabilistic Fracture Mechanics (PFM) and addressed the following phenomena associated with hydrogen blending:
    • Accelerated crack growth rates and 
    • Hydrogen embrittlement of the pipeline steel.
  • The POR was then evaluated for each active threat on the pipeline, comparing the risks associated with pure natural gas service to natural gas with hydrogen blending, considering various assessment options (hydrotest or ILI) prior to hydrogen injection.

CONCLUSION

Key challenges have been identified with blending hydrogen in gas transmission pipelines.  The susceptibility to failure of girth weld defects exposed to significant strain can be further exacerbated by the presence of hydrogen.  SI has developed a probabilistic framework and supporting tools to complete an ECA and provide a better understanding of the threats and subsequent impact to risk posed by cracks and crack-like defects in a hydrogen blending environment.

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News & Views, Volume 52 | PHMSA Rupture Mitigation Valve Rule

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PREPARING CLIENTS TO MEET NEW PIPELINE AND SAFETY REGULATION

By:  Bruce Paskett and Erica Rutledge

On April 8, 2022, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published amendments to 49 CFR Part 192 in the Federal Register issuing new valve installation and rupture detection requirements for onshore transmission pipelines and gathering pipelines .  The effective date of the Final Rule (“Valve Rule”) is October 5, 2022. 

The new rule is complex and creates challenges for operators. Since 2011, Structural Integrity has been advancing practical and cost-efficient methods to address pipeline safety. 

GENERAL OVERVIEW
As a result of two high-profile transmission pipeline accidents in 2010 , the congressional Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 PIPES Act) was enacted.  The legislation contained several mandates for PHMSA to issue regulations addressing improvements to pipeline safety.  One of the mandates required PHMSA to issue regulations for the use of Automatic Shut-off Valves (ASV) or Remote-Control Valves (RCVs), or equivalent technology, on newly constructed or replaced gas transmission pipeline facilities. 

The Valve Rule addresses this congressional mandate by establishing minimum standards for the installation of Rupture Mitigation Valves (RMVs) or alternative equivalent technology (AET) on specified newly constructed or entirely replaced onshore natural gas transmission, Type A gas gathering and hazardous liquid (e.g., oil and gasoline) pipelines that have diameters of 6 inches or greater.  

The Valve Rule covers the following topics:

  • New Definitions 
  • Rupture Mitigation Valves (RMVs)
  • Changes in Class Location and Valve Spacing
  • Emergency Plans and Response
  • Failure and Incident Investigation
  • Notification of Potential Rupture and Response to Rupture Identification
  • Valve Shutoff Requirements for Rupture Mitigation
  • RMV Valve Maintenance
  • Preventative and Mitigative Measures for Pipelines in HCAs

NEW DEFINITIONS (§192.3)
The Valve Rule defined “notification of potential rupture” as notification of, or observation by an operator, of the specific indications of an unintentional or uncontrolled release of a large volume of natural gas from a pipeline.  PHMSA has defined “rupture identification” to mean the point when a pipeline operator has sufficient information to reasonably determine that a rupture occurred.  

RUPTURE MITIGATION VALVES (RMVs) (§192.179)
The Valve Rule prescribes new rupture mitigation valve (RMV) installation requirements on certain pipeline segments with diameters of six inches or greater that are constructed or “entirely replaced” after April 10, 2023 in accordance with §192.179.  The RMV installation requirements only apply to entirely replaced pipelines if the addition, replacement, or removal of a valve is part of the replacement project.  

“Entirely replaced” is defined as replacing two or more miles, collectively, of any contiguous five miles of pipeline during a 24-month period.  

Gas pipeline segments in Class 1 or Class 2 locations that have a potential impact radius (PIR) of 150 feet or less are exempt from RMV installation requirements.

An RMV is defined as an automatic shut-off valve (ASV) or remote-control valve (RCV) “that a pipeline operator uses to minimize the volume of gas released from the pipeline and to mitigate the consequences of a rupture.”

Operators may elect to use an alternative equivalent technology (AET) in response to the RMV installation requirements if the AET provides an equivalent level of safety.  This process must be demonstrated and requested by the operator in a notification pursuant to §192.18 for PHMSA review. An operator requesting use of manual valves as an AET must include in the notification submitted to PHMSA a demonstration (e.g., evidence) that installation of an RMV would be economically, technically, or operationally infeasible. 

CHANGES IN CLASS LOCATION AND VALVE SPACING (§192.610)
The Valve Rule also applies where class location changes occur, and gas pipeline replacements are necessary to comply with Part 192 maximum allowable operating pressure (MAOP) requirements.  For Class Location changes that occur after October 5, 2022, and which are considered being entirely replaced, operators are required to comply with the valve spacing and RMV installation requirements. These valves must be installed within 24 months of the change in Class Location.    

For replacements not considered entirely replaced, the  operators must either:

  1. Comply with the valve spacing requirements in accordance with §192.179(a) for the replaced segment, or 
  2. Install or use RMVs or AETs so that the entirety of the replaced pipeline segment is between two RMVs or AETs. The distance between the RMVs/ AETs may not exceed 20 miles. 

The requirements above do not apply to pipeline replacements that are less than 1,000 feet within any single continuous mile during any 24-month period.

EMERGENCY RESPONSE (§192.615(a))
In the event of a potential or confirmed transmission or distribution pipeline rupture, the Valve Rule prescribes new requirements for operators to establish and maintain communication with appropriate public safety answering points (i.e., 9-1-1 emergency call center).  Operators must revise their procedures to require immediate and direct communication to 9-1-1 call centers or coordination with local government officials located in the communities and jurisdictions in which the pipeline rupture is located.

FAILURE AND INCIDENT INVESTIGATION (§192.617)
In the event of a pipeline rupture involving the closure of an RMV and/or AET, an operator must conduct an analysis of the factors that may have contributed to the rupture and implement measures to minimize the consequences of a future incident.  Operators must also complete a summary of the post-failure or incident review within 90 days of the incident.  The summary must be signed by a senior executive officer and retained for the useful life of the pipeline.

NOTIFICATION OF POTENTIAL RUPTURE AND RESPONSE TO RUPTURE IDENTIFICATION (§192.635)
The Valve Rule requires operators who identify a potential rupture or are notified directly from an external credible source(s) of a potential rupture, to take action(s) on their transmission pipeline system.  “Notification of potential rupture” may be based on one or more indications such as an unanticipated pressure loss greater than 10 percent in 15 minutes or less, an unanticipated flow rate or pressure change, or a rapid release of a large volume of gas, fire, or explosion in the vicinity of the pipeline.  

An operator must develop procedures documenting how it observes a potential rupture or receives notification of a potential rupture and the actions to be taken in response to a potential and confirmed rupture.  Upon notification of a potential rupture, operators must evaluate the potential rupture as soon as possible to confirm if it is a rupture. 

VALVE SHUTOFF REQUIREMENTS FOR RUPTURE MITIGATION (§192.636)
The Valve Rule prescribes new valve shut-off requirements. After rupture confirmation, the operator must fully close any appropriate RMVs or AETs necessary to minimize the volume of gas released from a pipeline and mitigate the consequences of the rupture as soon as practicable but within 30 minutes of rupture identification. Other valves necessary to isolate the pipeline segment must be closed as soon as practicable.

VALVE MAINTENANCE (§192.745)
PHMSA revised the existing §192.745 to require operators to conduct valve maintenance, inspection, and operator drill activities to ensure each RMV or AET can achieve the prescribed 30-minute valve closure time.  If during the drill, the 30-minute response time is not achieved, the operator must revise its rupture response efforts as soon as practicable to achieve compliance, but no later than 12-months after the drill.  Any valve found inoperable during this test must be repaired or replaced as soon as practicable but no later than 12 months after the valve is determined to be inoperable. The operator must also select an alternative valve to act as an RMV within seven calendar days.   

PREVENTATIVE AND MITIGATIVE MEASURES (§192.935)
The Valve Rule requires gas transmission operators to conduct a risk analysis/assessment on their transmission pipeline system to analyze whether an RMV or AET is an efficient means of adding protection to an HCA.  The risk analysis/assessment must consider timing of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and the location of the nearest response personnel. The risk analysis/assessment must be reviewed by operator personnel at least once per calendar year, not to exceed 15 months, and certified by a senior executive.

SI PROVIDES OPERATOR SUPPORT
Structural Integrity has significant expertise in pipeline safety regulatory compliance and has been heavily involved in the Valve Rule since 2011. Our dedicated and substantial resources are ready to help with specific procedures and programs, including: 

  • Risk Analysis and Assessment of RMVs on transmission pipeline systems.
  • Review and update of all existing procedures impacted by the new regulatory requirements, including emergency response, valve installation, operations, and maintenance.
  • Development of new, comprehensive procedures and processes to support compliance with the Valve Rule, which include defining Gas Control Room responses to potential ruptures, significant gas releases, and confirmed ruptures.

References

  1. PHMSA Pipeline Safety: Requirements of Valve Installation and Minimum Rupture Detection Standards Final Rule. 

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News & Views, Volume 52 | Understanding the Effects of Hydrogen Blending on Pipeline Integrity

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OIL & GAS SAFETY & RELIABILITY

By:  Scott Riccardella, Owen Malinowski & Dr. Pete Riccardella

Structural Integrity Associates is focused on evaluating the impact of hydrogen blending on pipeline integrity and establishing a roadmap for our clients to maintain the safety and integrity of their aging natural gas steel transmission pipelines.

Hydrogen is widely recognized as a viable, clean alternative energy carrier. Recent advances in technology for clean hydrogen production, as well as renewed governmental and organizational commitments to clean energy, have intensified interest in utilizing the existing natural gas pipeline infrastructure to transport hydrogen from production sites to end users. Energy companies are pursuing strategic pilot programs to evaluate the capacity of their natural gas transmission and distribution pipeline systems to safely transport blends of natural gas and hydrogen. These pilot programs demonstrate the commitment of energy companies to facilitate environmentally responsible energy production and consumption while identifying and investigating potential challenges to pipeline safety and integrity associated with hydrogen blending. 

KEY ELEMENTS OF THE EVALUATION INCLUDE

  • Completing a critical threat review using a phenomena identification and ranking table (PIRT) process with a team of experts.
  • Developing a statistical model for evaluating accelerated fatigue crack growth (FCG) in a hydrogen blend environment.
  • Developing a statistical model for evaluating reduced fracture resistance (hydrogen embrittlement).
  • Analyzing the impact of FCG and hydrogen embrittlement on the probability of rupture (POR) due to key threats such as stress corrosion cracking (SCC), longitudinal seam weld defects, and hard spots.
  • Implementing a joint industry project (JIP) to adapt SI’s APTITUDE software tool for evaluating predicted failure pressure (PFP) and remaining life resulting from SCC and FCG in a hydrogen blend environment.

CRITICAL THREAT REVIEW
As part of a systemwide evaluation for one of our clients, a large North American Pipeline Operator, a critical threat review using a PIRT process was conducted to comprehensively understand the potential impact of hydrogen blending on steel natural gas transmission pipeline integrity. To ensure a thorough and accurate PIRT was completed, a panel consisting of experts in metallurgy, fracture mechanics, hydrogen effects on steel properties, and pipeline operations was assembled. A vital part of the process was a series of meetings conducted with the pipeline operator, systematically identifying and ranking the importance of various phenomena that could adversely affect the safety and reliability of energy transportation through the operator’s existing transmission pipeline system.  

Figure 1. FCG rate curves in hydrogen (solid lines) versus air (dashed lines).

The PIRT panel reviewed all known pipeline integrity threats and identified potential unknown or unexpected threats that could be influenced by the presence of hydrogen in the operator’s transmission pipeline system. The process also assigned priorities for future research that may be needed to support that objective.

ENHANCED FATIGUE CRACK GROWTH
Significant research exists on the effect of hydrogen on FCG of pipeline steels and was referenced in this exercise. To gather the most relevant information possible, the project team compiled and analyzed data from numerous client-specific FCG tests of samples taken from the pipeline system in the targeted environment. These sample systems were exposed to equivalent hydrogen blend levels of 5%, 10%, 20%, and 100%. Over 2,200 data points were compiled and analyzed to develop trend curves and associated statistical variability. Data exhibited a significant increase in FCG rates (Figure 1) at relatively low hydrogen blend levels. ASME Code Case 2938 was reviewed and empirically fit with the analyzed data. 

 

Figure 2. Fracture toughness reduction as a function of hydrogen partial pressure for different pipe grades.

HYDROGEN EMBRITTLEMENT
Hydrogen is known to have an embrittling effect on carbon steels, such as those used in gas transmission pipelines. When an internal pipe surface is exposed to high-pressure hydrogen or a high-pressure mixture of hydrogen and natural gas, hydrogen gas can disassociate into hydrogen atoms, which can then be adsorbed into the steel and lead to material property degradation (such as reduced fracture resistance). Dislocations and defects in the steel can also act as hydrogen traps, leading to even higher hydrogen concentrations at the location of already vulnerable manufacturing defects and service-induced cracks. Reduced fracture resistance at such sites could increase the adverse effect on pipeline integrity by leading to more frequent pipe failure events.

Based on available data from the literature and input from the PIRT expert panel, the project team developed trend curves of percent reductions in fracture resistance due to hydrogen exposure (knockdown factors) relative to fracture toughness in air. From this analysis, a reasonably conservative approximation, including statistical variability, was developed for the region of interest (hydrogen/natural gas blend levels up to 20% – Figure 2). Additional research and data analysis are currently underway that may further validate the relationship and better study this effect at low hydrogen partial pressures, as well as confirm the knockdown effect on lower toughness pipeline materials, such as electric resistance welded (ERW) seam welds.

PROBABILISTIC FRACTURE MECHANICS
SI has developed Synthesis™, a Probabilistic Fracture Mechanics (PFM) tool that calculates the probability of rupture (POR) for various cracks and crack-like defects that have caused oil and gas pipeline failures. The software incorporates statistical distributions of all important parameters in a pipeline fracture mechanics calculation that uses a Monte Carlo analysis algorithm that randomly samples from each distribution and runs millions of simulations to estimate the probability of rupture versus time. To evaluate the impact of hydrogen blending, Synthesis has been adapted to incorporate the effects of hydrogen on pipeline steel properties (enhanced FCG and hydrogen embrittlement) and thus the ability to compare PORs with and without hydrogen blending. The modified software was then applied to several pipelines in the operator’s system to determine the POR ratio between various hydrogen blend levels and pure natural gas. Additionally, Synthesis can evaluate the effects of various mitigation measures, such as hydrotests and In-Line Inspections, that could be applied before injecting hydrogen (Figure 3). The calculated PORRs will allow the operator to prioritize pipelines and associated mitigating actions that may be more or less favorable for hydrogen blending.

Figure 3. Improvement in POR and PORR for different integrity assessments.

APTITUDE™ JOIN INDUSTRY PROJECT
SI has also established a JIP to adapt the APTITUDE PFP software program to handle some additional challenges presented with blending hydrogen with natural gas. Advancements include modifications that address enhanced FCG and hydrogen embrittlement. Further research to close gaps identified during the PIRT process is also being pursued through PRCI and other forums. Availability to join the JIP still exists, but space is limited – Please contact us if you would like to participate.

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Structural Integrity Associates | News and Views, Volume 51 | Selective Seam Weld Corrosion Engineering Critical Assessment

News & Views, Volume 51 | Selective Seam Weld Corrosion

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ENGINEERING CRITICAL ASSESSMENT

By:  Pete Riccardella, Scott Riccardella and Chris TippleStructural Integrity Associates | News and Views, Volume 51 | Selective Seam Weld Corrosion Engineering Critical Assessment

The Structural Integrity Associates, Inc. Oil and Gas Pipeline group recently supported an Engineering Critical Assessment to assist a pipeline operator manage the Selective Seam Weld Corrosion (SSWC) threat to an operating pipeline.  SSWC occurs when the fusion zone of a certain type of seam weld used in vintage (pre-1970) transmission pipelines experiences accelerated galvanic corrosion relative to the pipe body material.  It has led to numerous pipeline failures because the weld fusion zone often exhibits low fracture toughness.  The ECA included several technical advancements in applying fracture mechanics to this threat.

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SI Presents at PRCI AGA & ASME

Pipeline Integrity Activity and Plans for 2022

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Authors: Scott Riccardella and Andy Jensen

2021 marked another successful year for the Structural Integrity (SI) Oil & Gas team with several exciting pipeline integrity projects, industry presentations, training events and research programs.  Some of the key highlights include:

  • Continued regulatory consulting support of new pipeline safety regulation (known as Mega-Rule 1 or RIN 1) for nearly all our gas transmission pipeline clients.
  • Commencement of a systemwide pipeline integrity project to evaluate the impact to pipeline safety and reliability from blending hydrogen with natural gas (at various blend levels) for one of the largest U.S. gas pipeline companies.
  • Several industry presentations and training seminars on fracture mechanics evaluation of crack and crack-like defects in support of Predicted Failure Pressure (PFP) Analysis and Engineering Critical Assessments (ECA).
  • Completion of a PRCI study on state-of-the-art technology and a technology benchmark evaluation of X-Ray Computed Tomography to characterize Stress Corrosion Cracking (SCC) on full circumferential samples.
  • Development of a Neural Network algorithm and application of Probabilistic Fracture Mechanics to provide insight on the risk of SCC for a large interstate natural gas pipeline operator.
  • Development of an alternative sampling program for Material Verification when using In-Line Inspection tools including development of regulatory submittals.

2022 is also shaping up to be a similarly busy and exciting year.  Below are some of the events, conferences and presentations SI has currently planned (most of which represent ongoing or recently completed projects):

  • At the PRCI Research Exchange on March 8th in Orlando, FL, SI is presenting on two recent projects:

Insights in the Evaluation of Selective Seam Weld Corrosion

This paper will review a statistical analysis of ERW Fracture Toughness and specific challenges in evaluating Selective Seam Weld Corrosion (SSWC).  It also reviews the results of an engineering critical assessment performed on a pipeline system in which several SSWC defects were identified. Fracture Toughness Testing and Finite Element Modeling were performed to develop insights that were used to support Predicted Failure Pressure analysis and subsequent prioritization and remediation activities.

Title: Evaluation of X-Ray Computed Tomography (XRCT) for Pipeline Reference Sample Characterization

This presentation will review the feasibility of utilizing XRCT for nondestructively characterizing full-circumference pipeline reference samples for subsequent qualification and performance improvement of inline inspection and in-the-ditch nondestructive evaluation technologies, procedures, and personnel. This presentation will cover the state-of-the-art in XRCT, reviewing theoretical and practical concepts, as well as empirical performance data, that were evaluated and analyzed to determine the feasibility of using XRCT for this application.

  • SI has two papers that will be presented at the American Gas Association – Operations Conference the week of May 2nd in New Orleans, LA:

Alternative MV Sampling Program

SI will present technical justification in support of PHMSA notification with regards to the following:

  • Alternative sampling for Material Verification Program (per §192.607).
  • Expanded MV Sampling Program that will achieve a minimum 95% confidence level when material inconsistencies are identified.

A Framework for Evaluating Hydrogen Blending in Natural Gas Transmission Pipelines

Operators are establishing programs to blend hydrogen with natural gas.  Structural Integrity (SI) is supporting a local distribution company to ensure safe and reliable blending and transportation in existing pipeline infrastructure.  SI will present a reliability framework to identify pipelines that are best suited at different H2 blend levels.

  • SI will present at the 2022 ASME – International Pipeline Conference on the following topic:

Probabilistic Analysis Applied to the Risk of SCC Failure

This paper will discuss a model developed and applied to evaluate the probability of Stress Corrosion Cracking (SCC) failure in a large gas pipeline system spanning approximately 5,600 miles.  A machine learning algorithm (neural network) was applied to the system, which has experienced over 500 prior instances of SCC.  Subject matter experts were interviewed to help identify key system factors that contributed to the prevalence of SCC and these factors were incorporated in the neural network algorithm. Key factors such as coating type, vintage, operating stress as a percentage of SMYS, distance to compressor station, and seam type were evaluated in the model for correlation with SCC occurrence.  A Bayesian analysis was applied to ensure the model aligned with the prevalence of SCC.  A Probabilistic Fracture Mechanics (PFM) model was then applied to relate the probability of SCC existing to the probability of rupture.

Material Verification for Oil and Gas Clients Pipeline Integrity Solutions

News & Views, Volume 50 | Material Verification for Oil and Gas Clients

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PIPELINE INTEGRITY SOLUTIONS

By:  Scott Riccardella and Roger Royer

Material Verification for Oil and Gas Clients Pipeline Integrity SolutionsOn October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published amendments to 49 CFR Parts 191 and 192 in the Federal Register, issuing Part 1 of the Gas Transmission Mega-Rule or “Mega-Rule 1”.  In advance of Mega-Rule 1, SI developed field protocol and supported leading industry research institutes in validating in-situ Material Verification (MV) methodologies.  SI has continued to provide MV consulting support to our clients in response to Mega-Rule 1, ranging from program development and implementation to in-situ field data collection and analysis. 

Various sections of Mega-Rule 1 require operators of natural gas transmission pipelines to ensure adequate Traceable, Verifiable, and Complete (TV&C) material records or implement a MV Program to confirm specific pipeline attributes including diameter, wall thickness, seam type, and grade. Operators are now required to define sampling programs and perform destructive (laboratory) or non-destructive testing to capture this information and take additional actions when inconsistent results are identified until a confidence level of 95% is achieved. Opportunistic sampling per population is required until completion of testing of one excavation per mile (rounded up to the nearest whole number). 

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Oil and Gas Pipeline Intel - Industry Regulation Insights

News & Views, Volume 50 | Oil and Gas Pipeline Intel

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PRCI June Technical Committee MeetingsOil and Gas Pipeline Intel - Industry Regulation Insights

Structural Integrity Associates (SI) recently attended the PRCI June 2021 Technical Committee (TC) Meetings. SI is also planning to support the upcoming PRCI NDE workshop scheduled for October 2021 as well as future committee meetings. SI will continue to engage and support industry with PRCI.  As a researcher for PRCI, SI is pleased to support industry in the development and evaluation of new technology and methods that can enhance pipeline safety and reliability.  SI continues to support the development of new tools and analytical methods to help advance crack management, material verification, NDE inspections, and pipeline integrity management and share our experience with PRCI and industry.  Please contact us with any questions regarding our involvement or how SI can support your pipeline safety and reliability objectives.

SI Presenting at the 2021 AGA Operations Conference on “Responding to Cracks and Crack-Like Defects for Mega-Rule 1”.

Structural Integrity is pleased to partner with Duke Energy to present on Mega-Rule 1 requirements for the Analysis of Predicted Failure Pressure (192.712).  Procedures, tools and practical applications will be presented along with specific case studies.  In addition, methods to address additional requirements for evaluating cyclic fatigue will also be presented.  This presentation will be at the AGA Fall Operations Conference in Orlando, FL scheduled for October 6, 2021 at 10:45 AM in the Integrity Management track. Additional detail on the event can be found at the following site: www.aga.org/OpsConf2021

News & Views, Volume 49 | Mission Critica-nApplications to Support the Mega-Rule

News & Views, Volume 49 | Mission Critical Applications to Support the Mega-Rule

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News & Views, Volume 49 | Mission Critica-nApplications to Support the Mega-RuleBy:  Scott Riccardella, Bruce Paskett, and Steven Biles

On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published amendments to 49 CFR Parts 191 and 192 in the Federal Register, issuing Part 1 of the Gas Transmission Mega-Rule.  This new regulation is commonly referred to as the Mega-Rule since it represents the most significant regulatory impact on gas transmission pipelines since the original Gas Transmission Integrity Management Program (TIMP) Regulation was issued in 2003

The original Notice of Proposed Rulemaking (NPRM) issued in April, 2016 was split into 3 Parts, with the first Part (Mega-Rule 1) including specific requirements to address congressional mandates in the 2012 Pipeline Safety Reauthorization, and other pipeline safety improvements, including:

  • Maximum Allowable Operating Pressure (MAOP) Reconfirmation (§192.624),
  • Material Verification (MV) (§192.607),
  • Engineering Critical Assessments for MAOP Reconfirmation (§192.632),
  • Analysis of Predicted Failure Pressure (§192.712),
  • Assessments Outside of High Consequence Areas (HCAs) (§192.710),
  • Additional Requirements to Evaluate Cyclic Fatigue (§192.917(e)(2)), and
  • Additional Analysis of Electric Resistance Welded (ERW) Seam Welds (§192.917(e)(4))

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News & Views, Volume 49 | Digital Elevation Modeling Support Pressure Tests Records and Reduce MAOP Reconfirmation Costs

News & Views, Volume 49 | Digital Elevation Modeling: Support Pressure Tests Records and Reduce MAOP Reconfirmation Costs

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By:  Scott Riccardella, Bruce Paskett, and Eric Elder

§ 192.624(a)(1) of the Mega-Rule 1 requires MAOP Reconfirmation for steel transmission pipe segments if records necessary to establish the MAOP in accordance with § 192.619(a)(2) (e.g. pressure test), including records required by § 192.517(a), are not traceable, verifiable, and complete and the pipeline is located in a high consequence area (HCA) or a Class 3 or Class 4 location.

Part 192, Section 192.517(a) requires that natural gas pipeline operators shall make and retain, for the useful life of the pipeline, a record of the following information for any Subpart J Pressure Test (PT):

  1. The operator’s name, the name of the operator’s employee responsible for making the test, and the name of any test company used,
  2. Test medium used,
  3. Test pressur,
  4. Test duration,Pressure recording charts, or other record of pressure readings.
  5. Elevation variations, whenever significant for the particular test, and
  6. Leaks and failures noted and their disposition.

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