News & Views, Volume 53 | Serviceability Assessment of an L-Grade Stainless Steel Pipe Fitting

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By: Terry Totemeier

A client recently ordered a Type 316 stainless steel pipe coupling fitting for use in a high-pressure, high-temperature steam line operating at 1005°F.  The fitting that was received was so-called dual grade Type 316/316L stainless steel.  Given the limitations on using “L” grades of stainless steel at high temperatures, the client requested that SI perform a serviceability assessment for the fitting to determine if it could be safely used until the next scheduled outage when a replacement non-L grade fitting would be available.

BACKGROUND
The fitting ordered was a ½” nominal diameter (NPS ½), 6000# (Class 6000) full coupling socket-welding fitting in accordance with the ASME B16.11 specification, material ASME SA-182 forging, Type 316 stainless steel (designated as F316 in SA-182).  The fitting supplied was dual grade F316/316L material with a carbon content of 0.023% per the material test certificate.  The designation of this material as “dual grade” means that it meets the requirements of both F316 and F316L material grades.  This is possible because the chemical composition requirements of these two grades overlap, with the primary difference between them being carbon content.  For F316 the carbon content is specified to be 0.08% maximum (no minimum), while for F316L the carbon content is specified to be 0.030% maximum.  Therefore, material with carbon content less than 0.030% will meet the requirements for both grades.  It is worth noting that the carbon content of “H” grade of 316 stainless steel (F316H per SA-182) is specified to be 0.04-0.10%.  The H grade is intended for use at high temperatures.

The received fitting was installed in a main steam valve pressure equalizing line with a steam temperature/pressure of 2750 psia/1015°F at design conditions and 2520 psia/1005°F at operating conditions.  The fitting was welded to Grade P11 pipe on one side and Grade P22 pipe on the other side.  The applicable code was stated to be ASME BPVC Section I.

With a reported carbon content of less than 0.04%, the fitting is technically not permitted for use in ASME Section I construction above a temperature of 1000°F.  Per the ASME Boiler and Pressure Vessel Code (BPVC) Section II, Part D, Table 1A, the allowable stresses for SA-182, F316 material are valid at or above 1000°F only when the carbon content is greater than 0.04% (Note G12).  Per the same table, SA-182, F316L material is only permitted for use in Section I construction up to 850°F.  The reason for this temperature limitation is that the long-term creep-rupture strength of Type 316 stainless steel with lower carbon content is reduced compared to material with higher carbon content because fewer carbides form during service to strengthen the grain boundaries.  There are no other adverse impacts of the lower carbon content, e.g., on fatigue strength or oxidation resistance.

The short-term serviceability of the fitting with low carbon content was assessed by comparing bounding pressure stresses in the fitting with the reported creep-rupture strength for Type 316L material.  Per the ASME B16.11 specification, Class 6000 socket-welding fittings are compatible with NPS Schedule 160 pipe, meaning that pressure stresses in the fitting will be less than those in Sch 160 pipe with minimum wall thickness according to ASME B36.10 (pipe dimension specification), in other words, the fitting will be at least as strong as the pipe.  

ASSESSMENT
The dimensions of NPS ½, Schedule 160 pipe per the ASME B36.10 pipe specification are 0.84” outer diameter (OD), 0.165” minimum wall thickness (MWT).  For an operating steam pressure of 2,520 psi, the reference hoop stress per the equation in ASME BPVC Section I, Appendix A-317 is 5.05 ksi.  Per the general design guidance in ASME B16.11 (Section 2.1.1) the pressure stresses in the fitting must be less than this.  

Figure 1. Schematic diagram for a socket-welding coupling fitting. Per ASME B16.11, an NPS ½, Class 6000 fitting has relevant dimensions B = 0.875” maximum, C = 0.204” minimum, and D = 0.434” minimum.

Since the fitting in question is cylindrical, comparative hoop stresses can also be calculated from dimensions given in ASME B16.11, although these may not be exact due to the varied wall thickness in the fitting.  According to Table I-1 of ASME B16.11, the central body of the fitting is 1.283” OD and 0.395” MWT (Figure 1).  The reference hoop stress calculated using the A-317 equation at 2,520 psi stream pressure and these dimensions is 2.63 ksi, considerably less than 5.05 ksi.  In the female socket ends of the fitting, the OD is also 1.283”, but the minimum wall thickness is 0.204”, leading to a calculated reference hoop pressure stress of 6.58 ksi.  Note that the actual stresses in the socket ends will be much less than this because the pipe will be inserted and welded into the socket, taking up the pressure loading, but the calculated stress can be taken as a bounding value.

Creep-rupture strengths for Type 316L stainless steel have been reported in ASTM Data Series DS 5S2 publication, “An Evaluation of the Yield, Tensile, Creep, and Rupture Strengths of Wrought 304, 316, 321, and 347 Stainless Steels at Elevated Temperatures” (ASTM, 1969).  According to Table 7 in this report, the average 10,000 hour creep-rupture strengths for Type 316L at 1000°F and 1050°F are 34.5 and 25 ksi, respectively.  Minimum creep-rupture strengths are typically taken as 80% of the average strength, so the inferred minimum strengths at 1000°F and 1050°F are 27.6 and 20 ksi, respectively.  

The reported 10,000 hour creep-rupture strengths in the temperature range of interest are more than twice the calculated bounding pressure stresses in the fitting, so it was judged that there is very little risk of failure of the fitting by creep-rupture in the next 10,000 hours of service.

This result is unsurprising since the 1005°F is barely into the creep range for Type 316 regardless of carbon content.  The carbon content effects become more pronounced at higher temperatures (approximately 1100°F and above).

CONCLUSION
Based on the above assessment, it was SI’s opinion that the Type 316L fitting with carbon content less than 0.03% was suitable for a limited period of service (less than 10,000 hours) until it can be replaced.  Given that the fitting is reportedly welded to low-alloy steel pipe on either side, SI also recommended that a Grade 22 (2.25Cr-1Mo) low-alloy steel fitting be considered as a replacement, which would eliminate dissimilar metal welds (DMWs) between the fitting and pipes.  DMWs are prone to premature failure due to thermal fatigue, weld fusion line cracking, and decarburization of the ferritic material. This voluntary recommendation made by SI, was not part of the original scope of work, but may have been just as critical a finding as it shed light upon a failure risk previously unknown by the client. 

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News & Views, Volume 53 | Encoded Phased Array Ultrasonic Examination Services for Cast Austenitic Stainless Steel (CASS) Piping Welds

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IN PRESSURIZED WATER REACTOR (PWR) COOLANT SYSTEMS

By:  John Hayden and Jason Van Velsor

The CASS piping welds present in many PWR plants provide numerous and complicated challenges to their effective ultrasonic examinations. To this point, a viable ultrasonic examination solution for the inspection of these piping components, as required by ASME Code Section IX,  had previously not been available. By leveraging our technical expertise in materials, technology development, and advanced NDE deployment, Structural Integrity Associates, Inc (SI) has developed a new system that will provide a meaningful solution for the examination of CASS piping components. The result of this program will be the first commercial offering for the volumetric examination of CASS components in the nuclear industry.

BACKGROUND INFORMATION
ASME Section XI Class 1 RCS piping system welds fabricated using CASS materials pose serious and well-understood challenges to their effective ultrasonic examination. For decades, utilities and regulators have struggled with the administrative and financial burdens of Relief Requests, which were, and still are, based on the inability to perform meaningful volumetric examinations of welds in CASS components. 

Many years of futility and frustration may have fostered the belief that technology allowing effective and meaningful examination of CASS materials would never be achievable. This is no longer the case.

The failure mechanism for CASS material occurs through the loss of fracture toughness due to thermal aging embrittlement. The susceptibility of CASS material to thermal aging embrittlement is strongly affected by several factors, primary of which are system operating time and temperature, the casting method used during component manufacture, and molybdenum and ferrite content. In addition to the existing ASME Section XI requirements for the examination of welds in CASS materials, the susceptibility to thermal aging embrittlement drives the requirement for additional examinations (including ultrasonic examinations) as directed by several NRC-published NUREGs required for plant license renewal. The existence of a viable, effective examination capability for CASS materials plays a very important part in both currently required Inservice Inspections (ISI) and plant license renewal.

Figure 1. An example of the widely-varying microstructure of a centrifugally cast piping segment. False-color imaging is used to aid visualizing grain variations. (Image from NUREG/CR-6933 PNNL-16292)

CASS MATERIAL PROPERTIES AND EFFECT ON ULTRASONIC EXAMINATION
Metallurgical studies have revealed that the microstructure of CASS piping can vary drastically in the radial (through-wall) direction, as well as around the circumference and along the length of any given piping segment. Large and small equiaxed, columnar and mixed (combinations of equiaxed and columnar grains), and banding (layers of substantially different grain structures) are commonly observed in CASS piping materials. None of these conditions favor the performance of effective ultrasonic examinations.

Figure 2. PWR RCS Major Components

The very large and widely varying types (equiaxed, columnar, and randomly mixed), sizes and orientations of the anisotropic grains in CASS material are very problematic. Anisotropic is defined as an object or substance having a physical property that has a different value when measured in different directions. Such physical properties strongly affect the propagation of ultrasound in CASS material by causing severe attenuation (loss of energy through beam scattering and absorption), beam redirection, and unpredictable changes in ultrasonic wave velocity. These factors are responsible for the inability of ultrasonic examination to completely and reliably interrogate the Code-required volume (inner 1/3 Tnom) of welds in CASS piping material. Interestingly, CASS materials less than 1.6” Tnom (Pressurizer Surge Piping) can be effectively examined, while CASS materials over 2.00” (Main RCS Coolant Loop Piping) are less effectively examined.  Consequently, an ASME Section XI, Appendix VIII qualification program for CASS piping components has not been established and remains in the course of preparation. Nonetheless, ASME Section XI requirements to conduct inservice examinations of RCS piping welds fabricated from CASS components remain fully in force.

ASME CODE ACTIONS AFFECTING CASS PIPING EXAMINATIONS
ASME Section XI Code Case N-824, “Ultrasonic Examination of Cast Austenitic Piping Welds From the Outside Surface,” was approved by ASME in October 2012 and by the NRC in October 2019. This Code Case provides the first approved direction for the ultrasonic examination of welds joining CASS piping components. The ASME B&PV Code, Section XI, 2015 Edition, incorporates Code Case N 824 into Mandatory Appendix III in the form of Mandatory Supplement 2. To date, these two ASME Section XI Code documents remain the sole sources approved by ASME and NRC that provide specific direction for the examination of CASS RCS piping system welds and, therefore, form the foundation of SI’s approach for the development of our CASS ultrasonic examination solution.

SI’S CASS PROGRAM DESCRIPTION
SI is developing the industry’s most well-conceived and capable ultrasonic system for the examination of welds in CASS piping components. To accomplish this objective, SI has drawn upon our internal knowledge and experience, supplemented by a careful study of numerous authoritative bodies of knowledge relating to the examination of CASS components. The development of the SI examination system has been guided by both SI’s industry-leading 17 years of experience conducting phased array examinations in nuclear power plants and the knowledge acquired through the careful study of the topical information contained within industry-recognized publications. These published results of extensive industry research provided both guidance for the selection of phased array system components and CASS-specific material insights that strengthen the technical content of our Appendix III-based procedure. 

Figure 3. RCS Coolant Pump and Crossover Piping

CASS PROGRAM ELEMENTS
SI believes that the procedure, equipment and personnel featured in this program will be equivalent or superior to those that will form the industry-consensus approach for CASS ultrasonic examinations needed to successfully achieve Appendix VIII, (future) Supplement 9, “Qualification Requirements for Cast Austenitic Piping Welds.”

Ultrasonic Procedure – SI has crafted an ultrasonic examination procedure framework that is fully compliant with ASME Section XI, Mandatory Appendix III, Supplement 2, along with referenced Section XI Appendices as modified by the applicable regulatory documents.

Ultrasonic Equipment – SI has acquired and assembled the ultrasonic system components required by Code Case N-824 and Appendix III, Supplement 2, which includes the following:

  • Ultrasonic instrumentation capable of functioning over the entire expected range of examination frequencies. The standard examination frequency range extends from low-frequency, 500 KHz operation for RCS main loop piping welds through 1.0 MHz for pressurizer surge piping. 

SI has designed and acquired additional phased array transducers that meet the physical requirements of frequency, wave mode, and aperture size and are capable of generating the prescribed examination angles with the required focal properties. SI has designed and fabricated an assortment of wedge assemblies that will be mated with our phased array probes to provide effective sound field coupling to the CASS components being examined. SI’s wedge designs consider the CASS pipe outside diameter and thickness dimensions and employ natural wedge-to-material refraction to assure optimal energy transmission and sound field focusing.

SI also possesses several data encoding options that are necessary to acquire ultrasonic data over the expected range of component access and surface conditions. The encoding options will include:

  • Fully-automated scanning system, capable of driving the relatively large and heavy 500KHz phased array probes
  • The SI-developed Latitude manually-driven encoding system, which has been deployed during PDI-qualified dissimilar metal DM weld examinations in nuclear power plants

    Figure 4. Steam Generator Details

Examination Personnel – SI’s ultrasonic examination personnel are thoroughly trained and experienced in all elements of encoded ultrasonic data acquisition and analysis in nuclear plants. SI’s examiners have a minimum of 10 years of experience and hold multiple PDI qualifications in manual and encoded techniques. SI recognizes the challenges that exist with the examination of CASS piping welds and has developed a comprehensive program of specialized, mandatory training for personnel involved with CASS examinations. This training includes descriptions of coarse grain structures, their effect on the ultrasonic beam, and the expected ultrasonic response characteristics of metallurgical and flaw reflectors, as well as the evaluation of CASS component surface conditions.

ULTRASONIC TECHNQUE VALIDATION
Although not required by the ASME Code, SI has arranged for access to CASS piping system specimens from reputable sources to validate the efficiency of our data acquisition process and the performance of our ultrasonic examination techniques. The specimens represent various pipe sizes and wall thicknesses and contain flaws of known location and size to permit the validation and optimization of SI’s data acquisition and analysis processes. SI will thoroughly analyze, document, and publish the results of our system performance during the examination of the subject CASS specimens.

Figure 5. Pressurizer and Surge Line Details

CASS PIPING SYSTEM APPLICATIONS
Typical CASS Piping Weld Locations in PWR Reactor Coolant Systems
The following graphic illustrates the location and extent of CASS materials in the RCS of many PWR plants.

RCS Main Loop Piping Welds: This portion of the RCS contains large diameter butt welds that join centrifugally cast stainless steel (CCSS) piping segments to statically cast stainless steel (SCSS) elbows and reactor coolant pump (RCP) casings. RCS main loop piping includes the following subassemblies:

  • Hot leg piping from the Reactor Vessel Outlet to the SG Inlet
  • Cross-over piping from the SG Outlet to the RCP Inlet
  • Cold leg piping from the RCP Outlet to the RPV Inlet

Steam Generator Inlet / Outlet Nozzle DM Welds: These terminal end DM butt welds are present in PWR plants, both with and without safe ends between the SCSS elbows and the ferritic steel nozzle forgings. 

Pressurizer Surge Piping Welds: This portion of the RCS contains a series of butt welds fabricated using CCSS piping segments to SCSS elbows between the Pressurizer Surge nozzle end and the Hot Leg Surge nozzle. 

SUMMARY
The CASS piping welds present in many PWR plants provide numerous and complicated challenges to their effective ultrasonic examinations. SI’s new CASS ultrasonic examination system will provide a new and meaningful solution.

PROJECT TIMELINE
SI is working to complete the development, integration and capability demonstrations of the CASS ultrasonic examination system described in this document for limited (emergent) fall 2023 and scheduled deployments beginning in spring 2024.

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News & Views, Volume 53 | Phased Array Ultrasonic Testing (PAUT) Monitoring with Ultrasonic Thick-Film Arrays

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Traditional nondestructive examination (NDE) activities are planned based on hours of service, number of load cycles, time elapsed since previous inspections, or after the emergence of clear and obvious damage in a component. While engineering judgment and risk analysis can, and should, be used to prioritize inspections, these prioritizations are not based on the actual physical condition of the component or material it is constructed from but on precursory conditions that may or may not lead to eventual damage. Alternatively, continuous monitoring approaches can facilitate advanced planning and the optimization of Operations and Maintenance (O&M) spending by enabling the prioritization of inspections based on a component’s actual current condition. Furthermore, continuous monitoring enables earlier detection, which allows the extension of the component’s remaining useful life through modified operation. 

SI’s recent advances with thick-film are breakthrough technologies for long-term monitoring and imaging of crack growth in critical components.

Figure 1. Installed thick-film UT sensors for thickness monitoring of elbows.

Given the trend of fewer on-site resources and tighter O&M budgets, the energy industry has a strong motivation to progress toward condition-based inspection and maintenance. To facilitate this evolution in asset management strategy, new monitoring sensor technologies are needed, ones that provide meaningful monitoring data directly correlated to the condition of the material or asset. To support this need Structural Integrity has developed a novel thick-film ultrasonic sensor solution. Initially developed for basic applications, such as thickness monitoring, SI’s recent advances with this technology make long-term monitoring and imaging of crack growth in critical components possible.

BACKGROUND
Ultrasonic thick-films are comprised of a piezoelectric ceramic coating that is deposited on the surface of the component that will be monitored. A conductive layer is then placed over the ceramic layer, and the ceramic layer deforms when an electric potential is applied across the film. When a sinusoidal excitation pulse in the ultrasonic frequency range is applied across the film, the vibration of the film is transferred into the test component as an ultrasonic stress wave.   

Structural Integrity initially developed our thick-film ultrasonic sensors for real-time thickness monitoring and has demonstrated the performance and longevity of this technology through laboratory testing and installation in industrial power plant environments, as seen in the photograph in Figure 1, where the sensors have been installed on multiple high-temperature piping components that are susceptible to wall thinning from erosion. In this application, the sensors are fabricated directly on the pipe’s external surface, covered with a protective coating, and then covered with the original piping insulation. Following installation, data can either be collected and transferred automatically using an installed data acquisition instrument, or a connection panel can be installed that permits users to acquire data periodically using a traditional off-the-shelf ultrasonic instrument. Example ultrasonic datasets are shown in Figure 2.

Figure 2. Ultrasonic datasets from an installed thick-film UT sensor at two different points in time.

TECHNOLOGY ADVANCEMENTS
Recently, SI has demonstrated the ability to create thick-film sensors with complex element arrays that can be individually controlled to steer and focus the sound field, as with traditional phased-array ultrasonic testing (PAUT). Moreover, data from individual array elements can be acquired and post-processed using full-matrix capture (FMC) techniques. FMC is a data acquisition technique where all elements in the array are used to both transmit and receive ultrasonic waves. The result is a large data matrix that can be used for further processing with various post-processing techniques. Compared to more traditional active focusing, FMC is well-suited for a fixed transducer array, as scanning speed is not a concern. Another advantage is that the electronics needed for data acquisition can be simplified – requiring only a single pulsing channel.

A thick-film Linear-Phased Array (LPA) installed on a standard calibration block is shown in Figure 3. The two images shown on the right were generated using the Total Focusing Method (TFM) post-processing algorithm, with the image on the far right having an adjusted color scale to highlight the imaging of the notches toward the bottom of the calibration block. TFM is an amplitude-based image reconstruction algorithm where the A-scans from the FMC dataset are used to synthetically focus on every point in a defined region of interest.

Figure 3. FMC TFM results from a thick-film linear phased array installed on a calibration block.

Using other information from the FMC dataset, such as the phase of the waveforms, has proven to be beneficial in certain cases. At each focal point in the region of interest, a large phase coherence among all the waveforms can be indicative of a focused reflector. This can then be applied to the TFM image at each focal point as a weighting factor (also known as the Phase Coherence Factor (PCF)) to improve the signal-to-noise ratio. 

Figures 4 and 5 illustrate the results of applying the phase coherence imaging technique to the FMC datasets collected with thick film transducer arrays. The sample is a section of high-energy piping approximately 1.7 inches thick with cracking at various positions along a girth weld. The sample has a counterbore with ID-initiated cracks up to approximately 0.5 inches in length coming from the taper of the counterbore. The thick film transducer arrays were located at different positions along the weld.

SUMMARY
The energy industry is moving away from traditional scheduled-based planning for inspection and maintenance activities and toward “smart plant” concepts that rely more heavily on data correlated to actual component conditions. To accomplish this, there is a need for new and novel monitoring technologies that are both unobtrusive and able to withstand the harsh conditions of industrial facilities. Collecting robust and meaningful monitoring data will be critical in ensuring that safety and asset reliability are maintained and even improved. Structural Integrity’s thick-film UT technology has been developed to achieve this goal and continues to evolve for higher-temperature components and more advanced applications. We are ready to support a variety of in-field applications, contact one of SI’s experts if you have questions or a potential application that could benefit from installed thick-film UT sensors.

Figure 4. Phase coherence imaging result from a thick film transducer array on a cracked weld sample.

Figure 5. Phase coherence imaging result from a thick film transducer array on a cracked weld sample.

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 53 | Materials Lab Featured Damage Mechanism

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CIRCUMFERENTIAL THERMAL FATIGUE IN CONVENTIONAL WATERWALL TUBES

By:  Wendy Weiss

Circumferential Thermal Fatigue damage in Conventional Waterwall Tubes most commonly appears as circumferentially oriented cracking in the waterwalls of coal-fired supercritical units. Initially, the formation of ripple magnetite was a significant factor in the formation of this damage. Later, the introduction of oxygenated treatment controlled the formation of ripple magnetite, thus greatly reducing this damage mechanism.  In the early 2000s, however, this type of thermal fatigue began occurring more frequently as low NOx burners and separated overfire air systems were introduced. 

Figure 1. Tube with a series of circumferential cracks

Mechanism

Three basic factors contribute to this type of thermal fatigue damage. 

  1. The first factor is the starting tube temperature (i.e., the temperature under normal operating conditions). The higher the starting temperature, the greater the accumulation of damage in the affected tubing. For example, tubes subjected to higher heat flux or tubes with thick weld overlays will have higher average metal temperatures and accumulate damage more quickly. 
  2. The second factor is the extent of gradually increasing tube temperature caused by reasons such as internal deposit buildup, flame impingement, or unstable flow. 
  3. The third factor is the contribution of thermal transients due to slag shedding or using sootblowers or water cannons. 

Essentially, the thermal fatigue cracking results from the combination of increasing tube metal temperature and thermal transients and is aggravated by high starting tube temperatures. 

Figure 2. The external surface of the tube after the external deposits were removed

TYPICAL LOCATIONS

Figure 3. Cross-sectional views of the cracking in the etched (Top) and unetched (BOTTOM) conditions

  • Tubes with slag buildup and shedding
  • Areas affected by wall blow quenching
  • High heat flux locations
  • Areas affected by flame impingement
  • Cracking can be localized or widespread
  • Tends to be contained within a relatively narrow range of elevations

FEATURES

  • Circumferentially oriented, multiple, parallel cracks along the hot side of the tubes.
  • Notch shaped, oxide filled cracks in cross-section.
  • Adjacent tubes can exhibit variability in crack density.

ROOT CAUSES

  • High Initial Waterwall Tube Temperatures
    • Thick weld overlays
    • Higher heat flux
    • Flame impingement
  • Increasing Waterwall Tube Temperatures
    • Internal deposits including ripple magnetite, thick oxide layers, or feedwater corrosion products
    • Reduced internal flow rate
    • Formation of external oxides and deposits
  • Severe Thermal Transients
    • Natural or forced slag removal, including slag shedding and sootblowing
    • Use of water cannons or improper sootblowing
    • Flame instabilities
    • Unit operation, including forced fan cooling, rapid startups, frequent load cycling

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News & Views, Volume 53 | PEGASUSTM Nuclear Fuel Code

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ADVANCED FUEL MODELING DEVELOPMENT STATUS

By:  Bill Lyon

INTRODUCTION
The PEGASUS nuclear fuel behavior code features a robust 3D, finite element modeling (FEM) computational foundation capable of performing both thermo-mechanical and structural non-linear analyses within a highly versatile and customizable computational platform. The first applications of PEGASUS were for light water reactor (LWR) fuels and materials. Development work on PEGASUS has been extended to advanced fuel designs such as those proposed for Advanced Technology Fuel (ATF) LWR applications and Gen IV reactor designs, including gas and liquid metal-cooled reactors (GCRs and LMRs). 

The versatility and adaptability of PEGASUS is key in enabling extensions to non-conventional operating environments, materials, fuel forms, and geometries.

LWR APPLICATIONS
SiC Cladding

Figure 1. SiGA cladding is a multi-layered composite design composed of SiC fiber in a SiC matrix.

A project is underway to further the development and irradiation testing of a composite silicon carbide matrix as an ATF cladding material. This research is supported through a DOE Funding Opportunity award (DE-FOA-0002308) for the irradiation of a composite silicon-carbide (SiC) ceramic matrix material in an existing U.S. commercial LWR. This work is led by General Atomics – Electromagnetic Systems (GA-EMS) with Structural Integrity Associates (SIA) as a primary subcontractor. For this work, PEGASUS is being adapted to model monolithic and composite SiC manufactured by GA-EMS, SiGA [1], through the incorporation of proprietary material constitutive models. PEGASUS will then be used to provide independent test performance analyses aiding in the design of the irradiation vehicle and predicted material performance. The goal of the testing is to gather irradiation data under prototypic LWR operating conditions and to inform and confirm material performance models for the SiGA-based cladding. A follow-on activity is planned to evaluate the predicted performance compared to data gathered during the post-irradiation examination phase of the project.

Figure 2. Lightbridge Fuel Design PEGASUS Models

Cruciform Metallic Fuel
An additional fuel concept that has been explored using PEGASUS is a cruciform, extruded metallic fuel design proposed by Lightbridge Corporation [2]. This fuel is characterized by a unique multi-lobed fuel cross-section and features a U-50Zr fuel composition. Recent work has been published on fabrication testing of this proposed fuel design by Pacific Northwest National Laboratory (PNNL) [3]. PEGASUS has been used previously to prototype 2D and 3D geometric models and meshes of Lightbridge fuel and to perform fundamental temperature and stress distributions for this fuel under prototypic LWR conditions. PEGASUS has specific modeling tools designed to facilitate “extruded” 3D fuel designs that automate the meshing of these geometries. More work in this area is planned as a proposal has recently been awarded under the DOE NEUP program (DE-FOA-0002732) funding a collaborative project led by Texas A&M University along with Lightbridge, NuScale, and Structural Integrity Associates, Inc. (SI) for modeling this type of fuel for application in a LWR SMR.

 

URANIUM METAL ALLOY FUELS FOR SODIUM-COOLED FAST REACTORS
The initial implementation of metallic alloy fuel and stainless-steel cladding material constitutive models for prototypic fast reactor fuel designs in PEGASUS has been completed. Material properties and behavioral models for U-Pu-Zr fuel and HT-9 (high Chromium, martensitic stainless steel) cladding have been added. Ongoing work includes the implementation of a gaseous swelling and fission gas release behavior model for U-Pu-Zr fuel, a Zr-redistribution model, and a fuel-cladding chemical interaction (FCCI) model that includes the effect on cladding wall thinning.

To test the implementation of these models, benchmark tests were prepared that provided comparative data for assessment of the models’ performance. Test cases were chosen from two experimental series irradiated in EBR-II: X430, a 37-pin hexagonal sub-assembly, and X441, a 61-pin bundle. These experiments were designed to test numerous fuel rod design variables and fuel response as a function of fuel alloy composition, smear density, plenum-to-fuel volume ratio, power, and coolant conditions [4]. The general experimental fuel rod design corresponds to the typical driver fuel configuration shown in Figure 3.

Figure 3. Typical EBR-II Mark-III or Mark-IIIA Fuel Element [5]

Figure 4. Left: 2D Computational Model of Rod DP2, Right: Temperature Contour Plot of the Fuel Stack Region for Rod DP21 at Peak Power (plenum region removed for detail)

An illustration of the model and selected results from the initial analysis of rod DP21, assembly X441 are shown in the figures above. Figure 4 provides a diagram of the computational model showing the primary components of the model and a plot of the temperature distribution throughout the fueled region of the rod at peak power. Figure 5 provides the radial temperature profile across the fuel rod from the center to the cladding outer surface at peak power near the end of the irradiation period. Temperatures vary from just ~900 K at the pellet center to ~650 K at the cladding surface. The temperature differential is fairly low at ~250 K, as would be expected from a high-conductivity metal fuel rod with a Na-bonded fuel cladding gap. These results are consistent with published experimental observations.

TRISO FUEL MODELING DEVELOPMENT
Several advanced fuel material models have been implemented specifically for TRISO fuel in PEGASUS, including thermal and mechanical models for UCO or UO2 kernels, PyC, SiC materials, and a fission gas release model for computing the release of gaseous fission products such as Xe and Kr. In addition to the standard 3D and 2D axisymmetric modeling FEM capabilities in the code, PEGASUS contains several unique tools designed specifically to support TRISO fuel modeling and analysis. These include a “spherical mesh object” tool that can automate the process of generating 2D/3D TRISO spheres, meshing them, and embedding them into a fuel matrix to allow modeling of individual TRISO kernels or fully encapsulated TRISO fuel forms. An example of models generated using the spherical mesh object tool is shown in Figure 6. The spherical mesh object capability is, to our knowledge, unique to PEGASUS and not found in any other fuel performance or general-purpose FEM code. PEGASUS also has a “reshape” function that can automate the process of meshing and modeling deformed TRISO particles to increase user efficiency. Figure 7 illustrates particle meshes that were created using the reshape meshing tool.

These modeling capabilities allow PEGASUS to be used to investigate very detailed mechanical and structural effects in TRISO fuel forms. For example, enabling the detailed analysis of the mechanical interaction between TRISO fuel layers explicitly examining the effects of cracking, debonding, and asphericity within whole or damaged particles.

Figure 5. Radial Temperature Distribution Across the Fuel Rod Model at ~ 486 Days of Irradiation

Planned future development work includes the integration of damage-mechanics modeling and fission product diffusion in the TRISO particle, fuel compact, ad matrix. One failure mode of particular interest that has been identified is cracking of the IPyC layer which propagates through the SiC outer layer. This can create a pathway for enhanced fission product release from the TRISO particle to the surrounding fuel matrix. This failure mechansim appears to occur when the buffer layer remains bonded to the IPyC layer providing the conditions for a synergistic mechanical and chemical failure mechanism that combines cracking, stress concentration, and chemical corrosion (localized Pd-induced corrosion in the SiC [6]. This failure mode is of interest because it can have a strong impact on fuel source term determination for operational TRISO fuel.

Figure 6. Temperature distribution in a cross-section of a 3D slab of a TRISO compact matrix model with a “sparse”, random kernel distribution under prototypic gas-cooled reactor conditions. (Generated using the “spherical mesh object” tool.)

SUMMARY
PEGASUS is an advanced analysis tool developed for industry applications that can provide a complimentary and independent capability for nuclear fuel performance. Recent development work on PEGASUS has focused on expanding the applicability of the code to the advanced fuel (ATF) and advanced reactor arena. Future development is planned for PEGASUS that will continue along multiple avenues with an emphasis on advanced fuels and specific thermo-mechanical issues within the industry, such as deterministic failure model development. One example of this is the aforementioned Pd-induced failure mechanism identified for TRISO fuel. SI is actively seeking partners within the advanced fuel community to collaborate with on this work and would welcome inquiries and proposals for expanded application of PEGASUS.

 

Figure 7. Deformed 3D TRISO particle meshes generated using the “reshape” function tool in PEGASUS.

References

  1.   C. P. Deck et al., Overview of General Atomics SiGA™ SiC-SiC Composite Development for Accident Tolerant Fuel, Transactions of the American Nuclear Society, Vol. 120, Minneapolis, Minnesota, June 9–13, 2019.
  2.   J. Malone, A. Totemeier, N. Shapiro, and S.  Vaidyanathan, Lightbridge Corporation’s Advanced Metallic Fuel, Nuclear Technology, Vol 180, Dec. 2012.
  3.  Z. Huber and E. Conte, Casting and Characterization of U-50Zr, PNNL-33873, Pacific Northwest National Laboratory, Richland, Washington 99354, Jan. 2023.
  4.  C. E. Lahm, J. F. Koenig, R. G. Pahl, D. L. Porter, and D. C. Crawford, “Experience with Advanced Driver Fuels in EBR-II,” J. Nucl. Mat. 204 (1993) 119-123.
  5. G. L. Hofman, M. C. Billone, J. F. Koenig, J. M. Kramer, J. D. B. Lambert, L. Leibowitz, Y. Orechwa, D. R. Pedersen, D. L. Porter, H. Tsai, and A. E. Wright. Metallic fuels handbook, Technical Report ANL-NSE-3, Argonne National Laboratory, 2019.
  6. J.D Hunn, C.A. Baldwin, T.J. Gerzak, F.C. Montgomery, R.N. Morris, C.M. Silva, P.A Demkowicz, J.M. Harp, and S.A. Ploger, Detection and Analysis of Particles with Failed SiC in AGR-1 Fuel Compacts, Nuclear Engineering and Design, April 2016.

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News & Views, Volume 53

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The summer issue of Structural Integrity’s biannual technical newsletter, News and Views, is now available. We are excited to once again bring you this free source of technical information and advancements spanning multiple engineering disciplines and programs. In it, our expert team of Associates from our Nuclear, Energy Services, Pipeline Integrity Compliance Solutions, and Metallurgical Laboratory groups address vital topics relevant to your business.

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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 | Forecasting the Life of a Mass Concrete Structure, Part Two

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A CASE STUDY FROM THE FERMILAB LONG BASELINE FACILITY

By:  Keith Kubischta and Andy Coughlin, PE, SE

REFRESHER OF PART 1
From part one of the article (see News and Views Volume 51), we looked at the performance of a unique tubular mass concrete structure – the decay region of Fermilab’s Long Baseline Neutrino Facility – under complex thermal loading and thermal expansion. In the process of colliding subatomic particles in an accelerator and beaming them across the country underground, the facility contends with a massive amount of heat, an active nitrogen cooling system to remove energy, and shielding necessary for the surrounding environment. As we discussed in Part 1, Structural Integrity assisted with the design of the concrete structure by calculating the pertinent structural and thermal behavior under normal operation.  Now for Part 2, we focus on forecasting the future life of the structure using advanced capabilities in analysis and delve into the actual life of this concrete structure while considering the construction process, a 30 year planned cycle of life, and how these influence planning for structural monitoring systems. In doing so, we attempt to answer a larger question: What can we learn from this structure that could be applied to other past and future structures?

These methods are not only applicable to new structures.  Armed with the knowledge we can gain from record drawings, visual inspection, and non-destructive examination, SI is able to predict the life of concrete structures, new and old, giving key insights into their behavior in the future.

Figure 1. Fermilab Long Baseline Neutrino Facility (source https://mod.fnal.gov/mod/stillphotos/2019/0000/19-0078-02.jpg)

Figure 2. Adiabatic Temperature Rise for Concrete Placement

HEAT OF HYDRATION
In understanding the life of a structure, we must first start at the beginning as the concrete is first poured where another heat transfer takes place. Contrary to popular belief, concrete does not “dry”, rather it “bakes” itself during the curing process. As concrete is poured, it begins heating up internally through an exothermic hydration reaction between water and cement. The effect of the heat of hydration can usually be ignored in typical thin-walled structures. In larger mass concrete structures, however, the heat generation can cause significant degradation and built-in damage that can affect the structural performance throughout the entire life of the facility. 

A secondary subroutine as part of the ANACAP models is used for heat of hydration specific for construction analysis to convert the temperature rise into volumetric heat generation rate for thermal analysis. When heat is trapped deep inside the structure and can’t escape, the concrete exhibits a temperature rise similar to the curve in Figure 2, which is a function of the concrete mix proportions.

Figure 3. Placement Sequence of 164 Concrete Pours

CONSTRUCTION ASSESSMENTS
For the operating conditions covered in Part 1, the coupled 3D thermal stress analyses performed on this project were thermal conduction steady-state analyses. Construction of such a large concrete structure is subjected to additional requirements, and a Nonlinear Incremental Structural Analysis (NISA) was performed to evaluate the structure under the construction loadings. Herein, the thermal analysis during the concrete placement sequence requires a transient numerical solution methodology. This thermal analysis was used to monitor additional requirements for temperature during concrete placement, and a mechanical NISA study monitored the movement of the central cooling annulus vessel. The complete NISA coupled thermal-stress analysis simulated the entire construction phase over the period of a year and a half of the planned construction schedule. To accomplish this, the model was segmented into 164 concrete pours, each one activated (turned on) within the model on a specific day outlined in a construction schedule, as shown in Figure 3. As the concrete is poured on its specific day, the heat of hydration begins to heat up the internals of the concrete, the outside ambient temperature pulls the heat away from the concrete, and formwork insulates the heat transfer temporarily before being removed. As each new concrete segment is poured (activated in the simulation) it begins a new heat cycle, shedding heat into surrounding segments, changing surfaces that are exposed to air, or where the formwork is located. Upon completion of the thermal NISA study, Structural Integrity could advise on peak temperatures of each pour (Figure 4), compare internal to external temperatures and make optimal recommendations for insulation to keep the concrete from cooling too fast.

Figure 4. Thermal Views and Monitoring of Concrete Placement Temperatures

With the thermal NISA study completed, we then coupled the thermal with the mechanical stress analysis following a similar procedure. The model was broken up into the same 164 segments, with the reinforcement separated into individual segments. As a segment was poured, its weight was first applied as pressure on surrounding segments before the segment cured enough and took load. Formwork was considered a temporary boundary condition (simulated with stiff springs): activated then removed when appropriate. The concrete internal reinforcement was activated with each concrete segment. The cycles continue with each additional segment added. The concrete material for each segment had its own values for aging, creep, shrinkage, and thermal degradation for when the concrete was placed. The effect of creep and shrinkage could be significantly different for concrete poured on the first day and concrete that is poured a year later.  Mechanical tensile strain, a proxy for cracking, was plotted as shown in Figure 5.

A critical issue of concern was the steel annulus structure at the center of the concrete tunnel. The entire steel structure was placed prior to concrete being poured around it. The steel structure was affected by the thermal and mechanical loads of each concrete pour. Structural Integrity showed this structure “breathing” as thermal/mechanical loads pass from each concrete pour into the steel structure. Armed with a complete picture from the NISA stress analysis, Structural Integrity could show the animation of annulus movement, check the out-of-roundness, and advise on reinforcement placement. 

Figure 5. Concrete Mechanical Strain (i.e., Cracking) and Rebar Stress During NISA Construction

LIFECYCLE ASSESSMENTS
During the design phase, reinforced concrete structures are typically designed for a bounding range of expected loads, to include thermal load cycles, periodic live load variations, and/or vibration from mechanical equipment. Up to this point, the design phase analysis started from a “pristine” uncracked structure and applied the expected load with the beam and cooling at full power. Seldom is the cumulative impact of cyclic loading considered for the expected service life of the structure. Structural Integrity, having performed the NISA study, now had significantly more accurate state of the structure with expected cumulative damage already built-up. This gave us the unique opportunity to extend the analysis from the current state through the lifecycle of the structure, comparing the “pristine” to the “cumulative” case.

The expected life of the structure is 30 years of operations with the beam running for no more than nine months a year and three months off. These cycles are grouped together in either seven- or five-year blocks with a rest period of two years for maintenance or upgrades in between. The experiment starts small, ramping up the power to half the total output for the initial seven years. For the lifecycle assessment, time is still a critical element, not just for properties of concrete affected by time but the physical computational time. The transient thermal analysis would be too time intensive to run over the 30 years of life that we want to observe. To simulate the thermal cycles, the beam steady-state thermal response was calculated at each peak power level. This provided different thermal states of power, which the mechanical analysis could switch on or off as needed and interpolate between them to give a simulated ramp of power. The computational time could then be utilized on the mechanical stress lifecycle assessment.

Figure 6. Out-of-Roundness Check through Lifecycle, Ratcheting Effect of Power Cycles

With the completion of the lifecycles analysis, Structural Integrity could once again provide valuable information to the researchers and designers: deformations of the entire structure, deformations of the annulus, out-of-roundness of the annulus (Figure 6), estimates of crack width, etc.

Most importantly, we can answer and show comparisons between the designed load from a “pristine” model analysis to those from the “cumulative” analysis.

Even prior to the lifecycle assessment, the cumulative damage at the end of the NISA study signaled different behavior in the expected cracking (Figure 7). From the construction process, the concrete showed cracking near the boundaries between each concrete pour. These developed due to the natural thermal cycling of the construction process. The lifecycle thermal loading continued to push and pull the structure adding to the already existing cracks. Previously, the boundary point between the fixed rail and sliding rail section concentrated the thermal loading to induce significant cracking. Now the stress will be more evenly distributed throughout the upstream section. The cracking during construction provided natural thermal breaks along the whole length of the structure.

Figure 7. Concrete Strains at Various Point in Structures Lifecycle

HEAT DISPERSAL
SI then turned toward an additional question, where does all this excess heat go as the beam is cycling power? The shielding concrete is still heating up to over 60 degrees Celsius at the exposed surfaces. The air around the shielding concrete is trapped by the decay tunnel and venting conditions are unknown. We would need to produce a calculation based on the transfer of heat from the shielding concrete to the surrounding air/access tunnel, to the decay tunnel itself, and then the surrounding soil. Assuming the worst-case scenario, a point was selected along the length of the tunnel that produces maximum temperatures in the concrete. The cross section at this point is turned into a 2D model for use in a thermal analysis conducted as steady-state and transient to explore the heat transfer into the surrounding sections. A temperature profile of the decay tunnel wall was used to check its design from the thermal gradients, shown in Figure 9. The temperature of the air space between the structures can be monitored help in planning for when the tunnel can safely be accessed.

ONLINE MONITORING
Engineers at SI are always eager to add data to our models.  As this structure is constructed and put into service, the actual construction and startup sequence is likely to change, allowing for the model to be rerun and the lifecycle projection recalculated.  Furthermore, data from temperature sensors and crack monitoring gauges could potentially help calibrate the model based on observed conditions to improve the accuracy of our projections moving forward.  This methodology is applicable today to existing aging concrete structures where the lifecycle projection can be calibrated to existing observed conditions and data from online monitoring and non-destructive examinations.

Figure 8. Crack Width Estimation Based on Reinforcement Strain

CONCLUSIONS
Structural Integrity successfully developed expanded capabilities to model thermodynamics for the energy deposition and nitrogen cooling system. SI pushed the capabilities of our concrete model to capture over 30 years of construction and operations. Along the way, SI showed that our advanced modeling, combined with our advanced concrete model, positively influenced the design of the structure, and heavily supported the design and research teams with valuable information. The robustness of the calculation showed that SI is the present and future of concrete structure analysis.

SI demonstrated that our advanced modeling, combined with our advanced concrete model, positively influenced the design of this structure and heavily supported both the research and design teams with valuable information.

Figure 9. 2D Thermal Results of Decay Tunnel, Air Access Space, Shield Tunnel Walls, and Surrounding Soil

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News & Views, Volume 52 | Heat Exchanger Tube Sheet Reliability Analysis

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By:  Kannan Subramanian, PhD, PE, FASME & Dan Parker, PE

BACKGROUND

The hot section of a waste heat boiler, also known as the hot spent boiler, is an essential component in the regeneration of spent sulfuric acid in chemical plants that process sulfur. Due to the ever-increasing demand for sulfuric acid and other sulfur compounds, this is critical equipment as its operation results in sold-out production. As a result, these boilers need maximum uptime between scheduled maintenance outages; any unscheduled shutdowns to repair and/ or replace tubes and tube sheets directly translate into lost revenues for the plant. This article addresses the reliability issues of one such boiler located in a Louisiana chemical plant. 

GOAL: Predict the minimum number of tubes to plug, minimize downtime and allow regular operation until the next planned maintenance.  

Figure 1. Hot Spent Boiler (shaded in red) in a waste heat recovery unit Flue Gas Tube Boiler.

Figure 2. Tube-to-tube sheet joint failures and tube sheet leak

The boiler being assessed was part of an arrangement (Figure 1), with two fire tube boilers in parallel with a common external steam drum. In the case of the single boiler assessed by SI, the tubes were experiencing periodic tube leaks as the boiler was approaching the end of service life where tube failure frequency increases. As typical, there may be a single tube leak or several in the same proximity (Figure 2). Some proactive plugging has been applied based on historical performance (Figure 3(a)). In SI’s experience, tubes adjacent to a plugged tube may fail a short time after the plug is installed as there is an undefined temperature/stress interaction. In addition to tube leaks, general corrosion and tube sheet thinning can be a consequence of tube leaks (Figure 2(c). Excessive tube sheet thinning is not uncommon due to the formation of sulfuric acid that exacerbates the corrosion issue. With these consequences in mind, it is critical that the proper number of tubes be plugged to stop the costly cascade of failures. 

To bring the boiler back to service, in early January of 2022, the leaking tubes and a few other tubes around the leaking tubes were plugged. In addition, to repair the leaking location in the tube sheet knuckle region, welding followed by post-weld heat treatment was performed (Figure 3(b)). Within a few weeks after this repair, additional tube leaks were discovered and required plugging. Such frequent leaks and repairs result in production loss and unplanned expenses. To minimize those, SI was contracted to develop an engineering basis for tube plugging, which would be proactive for equipment reliability, but not produce over-plugging that affects the boiler heat duty. To achieve this, the engineering assessment should involve an advanced analytical study to understand the following:

  • Tube leaks
  • Effect of repair, PWHT, and additional plugging on adjacent unplugged tubes
  • Effect of tube sheet metal loss on the integrity of the tube sheet

This article covers both the historic details of the failures and subsequent repairs and provides a comparison of the failures documented on-site with the analytical results determined from the approach implemented by SI. 

Figure 3. Hot Spent Boiler Plugging and Repair Welding

METHODOLOGY & CRITERIA

The overall approach adopted by SI: 

  • Develop finite element (FE) model to study design deficiencies, if any, using elastic analyses. That is, perform an elastic finite element analysis (FEA).
  • Develop a criterion to study the tube-to-tube sheet integrity.
  • Using the same FE model, perform elastic-plastic analyses to determine the effect of repair and PWHT. 
    • This is to determine if any additional tubes should be plugged to reduce any adverse effects.
    • This is a sequentially coupled thermal-stress analysis.
  • Calculate the minimum required thickness for the various sections of the waste heat boiler.
Table 1. Criteria Used in the Analyses

Table 1. Criteria Used in the Analyses

Table 1 illustrates the criteria considered for the work described herein. Several stress magnitudes were considered, such as the tube material allowable stress, tube-to-tube sheet joint allowable stress, and the ratcheting limit. Typically, when elastic analyses are performed, ratcheting limits are helpful. However, this work did not utilize the ratcheting limit. The tube-to-tube sheet joint allowable stress and load are calculated using Section VIII, Div. 1, Nonmandatory Appendix A. The allowable stress and load are compared against the equivalent stresses and tube axial loads, respectively, from the FEA to determine the mechanical integrity of the tube-to-tube sheet location. However, since there exists a parallel damage mechanism (general corrosion), the yield strength of the tube is set as a limit to add conservatism.

Figure 4. Hot Spent Boiler as Modeled in FEA

 

ANALYSES & RESULTS

Since the methodology requires the use of advanced analytical methods, an FEA model (Figure 4) was built and analyzed using the commercial FEA software package – Abaqus. The model included sufficient lengths of gas inlet and outlet sections, the tube support location at the mid-section of the mud drum, the refractory, and the brackets that connect the hot section with the boiler drum. Since the nozzles are far from the area of interest, they are not included in the model. Appropriate element types were utilized for this work. One notable feature is the use of beam elements for the tubes (Figure 5). Since the model includes hundreds of tubes, incorporating a solid tube and heat exchanger model adds both geometric and numerical complexity. The use of beam elements simplifies the model while significantly minimizing the numerical convergence issues when compared with the full solid models. 

Figure 5. Hot Spent Boiler Tubes Inside the FEA Model

All the analyses performed are thermo-mechanical analyses, wherein a heat transfer/thermal analysis is performed first, and the temperature profile from the thermal analysis is imposed along with respective mechanical loads in the subsequent stress/mechanical analysis. Initially, elastic models were used to assess the design adequacy of the subject boiler and to determine the bounding operating conditions for further analyses involving the repair process. For the analyses involving the weld repair and the post weld heat treatment (PWHT) followed by operating conditions, the sequence of steps is critical. SI discussed the methodology with the client when developing the accurate sequence to be included in the FEA. As stated earlier, to capture the effect of residual stresses (after welding and PWHT processes) on the corroded tube sheet section at the bottom where the leak was discovered, an elastic-plastic FEA is essential. Temperature results from the welding process step are shown in Figure 6. After welding and PWHT, the process conditions were applied to the model along with the number of plugged tubes at the time. Figure 7 illustrates the temperature distribution in the tube sheet, boiler drum, and tubes. Since the plugged tubes do not transport flue gas, the temperature of those tubes is the same as the water temperature around those tubes inside the drum.

Since the number of tubes is significant, post-processing of results is a challenge. SI developed a procedure to overlay the von Mises equivalent stress results on a spreadsheet layout that resembles the actual tube layout in the tube sheet. It is further simplified for better visualization in this article, as shown in Figures 8 through 10. Figure 10 (a) shows a historical perspective of the tube plugging over time. In the first set of analyses that SI performed, only the locations shown with greyish blue color (tubes plugged before Jan. 2022) were considered as plugged. The thermal analysis results for this case are shown in Figure 7. After performing the mechanical/stress analysis, it was observed that the unplugged tube locations shown in Figure 8 (a) with orange and red dots are of concern. The orange dot locations indicate the locations with stresses greater than the tube yield strength. The red dot locations indicate that the stresses exceeded the allowable stress. Since the criteria are set at joint location stresses exceeding the tube allowable stresses, both orange and red dot locations require tube plugging. Figure 8 (b) shows the locations where further tube leaks were discovered within weeks of the weld repair and plugging. The tube leak locations are identified with yellow marks. This gives the confidence that such analytical methods, when appropriately applied, can predict the locations of future failures.

Figure 6. Repair Welding Simulation – Heat Transfer Analysis

Figure 7. Post Repair and Plugging Process Conditions – Heat Transfer Analysis

After the discovery of the new leaks, further plugging was undertaken. These locations are identified by light blue dots in Figure 10 (a). SI incorporated these changes in the analyses and determined that the locations shown in red and orange dots in Figure 8 (a) are still a concern, as shown in Figure 9 (a). This was later confirmed by further tube leaks (see Figure 9 (b)) found after 6 weeks of the previous plugging was completed. This further assured the value of performing such an engineering-based approach rather than a traditional grand-fathering approach which would use plugging methods adapted for similar units based on historical information. It should be noted that SI was engaged in this study at the period between weld repair and second set of plugging as shown in Figure 8. However, all the results were made available just prior to the third leak shown in Figure 9 (b). At this time, the Client utilized the results from the FEA and decided to add additional tube plugging as shown in Figure 10. SI performed analyses with the final set of plugging, and the results indicated that other tube locations around the plugged tube locations are not of concern (see Figure 10 (b)).

Figure 8. Post Repair and Plugging Process Conditions Criteria Check and Field Observation

Figure 9. Additional Plugging and Field Observation after that Plugging

The last set of analyses were performed in mid-March of 2022, and after 6 months, the boiler did not experience any further leaks. While the engineering approach predicted the issues, it is cautioned that any engineering analysis can only simulate the known degraded material thickness and properties in the analysis and not the corrosion degradation mechanism itself. The rate of deterioration and the interaction of various damage mechanisms should be monitored by the operator.

Figure 10. Tube plugging to-date and tube-to-tube sheet joint stress state

CONCLUSIONS

  • The original, as-installed condition did not show significant issues. It is believed that other damage mechanisms caused the initial failures leading to the plugging of tubes around the periphery of the tube sheet.
  • The study captured the recent joint issues, specifically the failure after the plugging and repair weld performed in early January 2022. 
  • Thinner regions are more prone to further failure. The minimum required thickness using the same criteria is established for the tube sheet.
  • The analysis was successful in predicting the minimum number of tubes to plug.
  • Plugging the correct number of tubes stopped the typical tube failure cascade.
  • The applied results were directly proven. Once the results were fully implemented, the waste heat boiler had no unplanned shutdowns. The analysis met its goal and provided a major business impact.
  • Analysts need sufficient information to minimize assumptions and make a robust model.
  • Clear understanding of API 579, ASME Section VIII Div. 1, ASME Section I, and FEA is necessary to develop robust, realistic, and relevant engineering solutions.

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