Figure 1 – Photograph of an ultrasonic thick-film array for monitoring wall-thickness over a critical area of a component.
The ability to continuously monitor component thickness at high temperatures has many benefits in the power generation industry, as well as many other industries. Most significantly, it enables condition-based inspection and maintenance, as opposed to schedule-based, which assists plant management optimizing operations and maintenance budgets and streamlining outage schedules. Furthermore, it can assist with the early identification of potential issues, which may be used to further optimize plant operations and provides ample time for contingency and repair planning.
Over the last several years, Structural Integrity has been working on the development of a real-time thickness monitoring technology that utilizes robust, unobtrusive, ultrasonic thick-film sensor technology that is enabling continuous operation at temperatures up to 800°F. Figure 1 shows a photograph of an installed ultrasonic thick-film array, illustrating the low-profile, surface-conforming nature of the sensor technology. The current version of this sensor technology has been demonstrated to operate continuously for over two years at temperatures up to 800°F, as seen in the plot in Figure 2. These sensors are now offered as part of SI’s SIIQ™ intelligent monitoring system.
Figure 2 – A plot of ultrasonic signal amplitude over time for a sensor operating continuously at an atmospheric and component temperature of 800°F.
In addition to significant laboratory testing, the installation, performance, and longevity of Structural Integrity’s thick-film ultrasonic sensor technology has been demonstrated in actual operating power plant conditions, as seen in the photograph in Figure 3, 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 external surface of the pipe, 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 periodically acquire data using a traditional off-the-shelf ultrasonic instrument.
Figure 4 shows two sets of ultrasonic data that were acquired approximately eight months apart at an operating power plant. The first data set was acquired at the time of sensor installation and the second data set was acquired after approximately eight months of typical cycling, with temperatures reaching up to ~500°F. Based on the observed change in the time-of-flight between the multiple backwall echoes observed in the signals, it is possible to determine that there has been approximately 0.005 inches of wall loss over the 8-month period. Accurately quantifying such as small loss in wall thickness can often provide meaningful insight into plant operations and processes, can provide an early indication of possible issues, and is only possible when using installed sensors.
Other potential applications of Structural Integrity’s ultrasonic thick-film sensor technology include the following:
Real-time thickness monitoring
Flow Accelerated Corrosion (FAC)
Erosion / Corrosion
Crack Monitoring
Real-time PAUT
Full Matrix Capture
Critical Area Monitoring
Other Applications
Bolt Monitoring
Guided Wave Monitoring
In addition to novel sensor technologies to generate data, Structural Integrity offers customizable asset integrity management solutions, as part of the SIIQ platform, such as PlantTrackª, for storing and managing critical data. Many of these solutions are able to connect with plant historians to gather additional data that feed our engineering-based analytical algorithms, which assist in converting data into actionable information regarding plant assets. These algorithms are based on decades of engineering consulting and assessment experience in the power generation industry.
Reach out to one of our NDE experts to learn more about SI’s cutting-edge thick-film UT technology.
Figure 3 – Photograph showing Structural Integrity’s thick-film ultrasonic sensor technology installed on two high-temperature piping elbows that are susceptible to thinning from erosion.
Figure 4 – Ultrasonic waveforms acquired approximately 8 months apart showing 0.005 inches of wall loss at the sensor location over this period.
By: Pete Riccardella, Scott Riccardella and Chris Tipple
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.
PEGASUS, a finite element fuel code developed at SIA, represents a new modeling paradigm. This new paradigm treats all fuel behavior regimes in one continuous analysis.
Introduction PEGASUS, a finite element fuel code developed at SIA, represents a new modeling paradigm.This new paradigm treats all fuel behavior regimes in one continuous analysis.This approach differs significantly from the current conservative practice of bounding analysis to ensure uncertainties are accounted for which results in sub-optimal used fuel management strategies.Using PEGASUS in used fuel evaluation results in significant savings in engineering cost and work force utilization, reduces conservatism, and provides flexibility in the management of used fuel.
From Tech Pro Research, %’s reflect rate of respondents who believe digital transformation will significantly impact indicated categories
A fundamental tenant of engineering is that where inefficiencies exist, innovation is next.This is especially true in the ongoing era of digital transformation, as software-based automation eliminates mundane, trivial tasks and enables increased focus on value-add activities.A recent poll of workers in the tech industry found that 70% of their respective companies have either committed to or are developing a transformation strategy, with varying emphases (see sidebar).The energy sector is no stranger to these innovations, and while the pace and scope of digital transformation may not appear to match that of driverless cars or moon rockets, its societal impacts are comparably widespread.
Historically, SI has been recognized as a leader in highly technical subject matter areas such as fracture mechanics, material degradation, and nondestructive examination.In many cases, this expertise is aided by digital or software innovations that enable efficient data handling, novel computer aided visualizations, and dynamic performance of complex calculations.In this vein, our MAPPro software is designed to aid in management of aging piping assets and has been an integral resource to the nuclear industry since its inception in 2009.
By: Matt David, Michael Greveling, Daniels Peters and Erick Ritter
Recently, Structural Integrity Associates (SI) helped a client with a leaking deaerator tank (DA tank). DA tanks are traditionally used to remove dissolved gasses from liquids. The client’s DA tank in particular is used to remove dissolved oxygen in feedwater for steam-generating boilers; this is done because dissolved oxygen can create a corrosive environment within the boiler as it will attach to the metal components, creating oxides. The DA tank protects the boiler from these corrosive gasses, however, to the DA tank’s detriment, not much protects it from those same gasses. Repairs on DA tanks are common and additionally it is not uncommon for those repairs to continue to experience problems.
The DA tank being investigated for leaking in this investigation had an entire shell segment, various full thickness patch plates, and a head replaced in 2018 due to wall thinning caused by flow-accelerated corrosion (FAC). The current leak was caused by cracking of a girth and longitudinal seam weld in a mismatched repair patch. The failure prompted inspection, stress analysis, and repair consulting by SI. The following reveals the steps taken to repair the failed DA tank.
Initial visual inspection of the leaking DA tank indicated that the problematic repair patch had significant radial mismatch relative to the tank shell to which it was welded and grossly oversized weld layers resulting in high tensile shrinking stresses. The mismatch resulted in significant bending at the weld line and the excessive weaving of the weld layers led to tensile forces acting on the weld imperfections at the toe of the welds. Due to the visual finding, 3D scanning was performed to better understand the magnitude of the mismatch.
Figure 1. Compressor rotor inlet with fouling deposits
An industrial combustion turbine can ingest over 1000lbs of air per hour of operation.Entrained within the air is a spectrum of mineral, salt, moisture, and VOC, and other compounds that are present in the local atmosphere.Locally high concentrations of potentially corrosive species may also be present due to surrounding industries or even effluent from the power plant itself, such as cooling tower drift, evaporation cooler deposits, or water treatment effluent.
In addition to disrupting the flow path area of the compressor blades and vanes, with a consequential drop in compressor efficiency, these contaminants can also serve as sites for under-deposit corrosion cells that have implications for component life as well as risk for catastrophic failures.Compressor waterwashing with detergents has been utilized with some success by utilities as a method for mitigating the effects of deposit accumulation.Nevertheless, tenacious deposits can accumulate over time.The presence of moisture in the deposit can also result in activation of a corrosion cell that can corrode the typical stainless steels used for blade and vane construction.Higher strength PH stainless steel blades and vanes suffer a larger loss in fatigue endurance limit from pitting, and tend to suffer more airfoil liberations due to cracking initiated at pitting.
Figure 2. Forward compressor blade with leading edge pitting
On forward compressor blades and vanes, qualified inspectors have also observed combined effects of leading edge erosion and pitting.The erosion is typically the result of on-line water washing.The roughness of the eroded leading edge is now an ideal area for compressor deposits to become deeply embedded.Additionally, it serves as multiple stress concentrations for fatigue crack initiation.
The fall in compressor efficiency, the irreversible damage due to erosion and corrosion pitting, and the risk of catastrophic damage due to fracture initiation at the affected areas, all suggest that O&M staff need to have a strategy to mitigate compressor deposit accumulation, as well as erosion channeling.Additionally, the strategy should also consider the scenario where some deposit accumulation is unavoidable and how to reduce the activation of these deposits.Consideration should also be given to units that have a history of blade failures due to a design limitations that makes them susceptible to corrosion fatigue cracking.In such cases, the unit has a low tolerance to the presence of corrosion pitting for crack initiation.
Figure 3. Fractured forward compressor blade with leading edge pitting at the origin
Typical Sources of Contamination – Land
Local geology and soil can contain large amounts of calcium, iron, magnesium, aluminum potassium, sodium, phosphorus, sulfur, as well as other less common species, including chlorides where the dry land used to be a sea bed.These elements are usually present as a compound, such as a mineral oxide or a salt, but may also be bound with organic material in the soil.Even with reasonably high efficiency filtration that removes 99.7% of the particulates within a given particle size range, the remaining 0.3% contamination multiplied by 1000lbs /hr of influent air results in a high rate of deposit accumulation.Deposits accumulated on airfoil surfaces can then liberate ionic species due to the absorption of moisture, thus creating a corrosion cell.Chlorides due to ubiquitous salts will rapidly corrode (pit) any and all of the stainless steels used in gas turbine compressors, with only partial mitigation by coatings.The only class of compressor materials reasonably immune to chloride or under deposit corrosion is the titanium alloy blades and vanes used in flight turbines and some aeroderivative units.Sulfur containing compounds are also commonly found on the airfoils of compressor blades and vanes, particularly in regions with heavy industry and refining.Sulfur containing compounds can also be extracted and diverted to the hot gas path cooling channels of downstream components, and greatly accelerate hot corrosion in the absence of moisture.
Atmosphere
The local quality of air entering the compressor is somewhat variable, and also dependent on geographic location.Coastal regions have an obvious problem with humid, chloride laden atmosphere.This particular environment is especially vulnerable to chloride pitting.Special inlet ducting and tailored filtration may provide some level of protection.
Figure 4. Fractured forward compressor blade with leading edge erosion at the origin
Figure 5. Forward compressor blade with leading edge erosion at platform radius
Local environments due to the proximity of inlets relative to cooling towers and the use of sodium hypochlorite for microbial control of cooling tower water can result in a chloride-laden influent to the unit.In this case the solution may be as simple as using a non-chloride based biocide for microbial control.In some cases the corrodents can come from non-typical activities at the plant, such as excursions of acid vapors from the water treatment facilities (sulfuric acid or hydrochloric acid).
Proximity to local industry, such as steel mills, coal or lignite fired boilers, oil production or refineries can result in a large influent concentration of sulfur bearing compounds.Sulfur bearing compounds, when incorporated into a deposit layer, can accelerate under-deposit corrosion and pitting, as well as aforementioned hot corrosion of downstream turbine components.
Water
Water source used for compressor washing (online and offline), as well as water used for power augmentation (misting, evaporative cooling, etc) should ideally be demineralized quality or better.The use of city water or another source of hard water is generally discouraged.Online water washing with a hard water source can result in increased deposit accumulation at and beyond the phase transition area (stage 2-5 typically) where the water boils to vapor and the dissolved minerals will deposit onto the blade /vane surfaces.Power augmentation by closed loop chiller systems also affords the opportunity for contamination due to leaks in the chilled fluid.These fluids can have variable water quality as well as chemicals added to the chiller loop.Non volatile constituents of the chilled water may leave deposits in a similar fashion as hard water.Evaporative cooling with hard water will result in mineral shedding that can accumulate downstream.As mentioned, on-line water washing will often cause leading edge erosion channeling, and more severely if the droplet size is not controlled, or leaking occurs during operation.
Historical Contaminants Observed in Compressor Deposits
Over the course of many years, we have been privileged to sample the deposits laden on blades and vanes from gas turbine units in many parts of the world.A pattern of contaminants (the usual suspects) has been observed, with some exceptions.The deposits observed are biased largely by one of the dominating contributors:Coastal conditions, land conditions, or local plant and industrial environment (neighboring industry or locally produced effluent).
Figure 6. Forward compressor blade with leading edge erosion at airfoil mid span
Energy Dispersive Spectroscopy (EDS) provides qualitative elemental analysis of materials under scanning electron microscopy (SEM) examination based on the characteristic energies of x-rays produced by the electron beam striking a deposit sample.The relative concentrations of the identified elements are determined using semiquantitative, standardless quantification (SQ) software.This information can be used to tailor the filtration system and media, as well as the detergents used in compressor washing.It may also provide leverage for high level dialog with the local regulators and emitting sources.
Conclusions
The corrosion pitting on the compressor blades and vanes is almost always the result of under-deposit corrosion aggravated by the presence of corrosive species in the deposit.The corrosive species are often sulfur and chlorine-containing compounds, but pitting can also occur from simply the presence of oxygen under the deposit (oxygen pitting).The pitting is proof of corrosive deposits, and trace amounts of corrosive species identified by EDS at the bottom interface of the pits identifies the active corrodents so that treatment can be fine-tuned for that species.
The source of the corrodents can be local to the plant (cooling tower drift), in the soil, from the atmosphere (coastal chlorides) or from local industry (burning lignite or low grade coal, and / or oil and gas production).In some cases the corrodents can come from non-typical activities at the plant, such as the use of sodium hypochlorite (bleach) for biological control, or excursions of acid vapors from the water treatment facilities (sulfuric acid or hydrochloric acid).Plant operations can identify, address and mitigate the local sources.
Starts-based units, or peakers, also have life-limiting pitting that is difficult to understand without considering the effect of off-line corrosion.For units operating in cycling duty, a substantial amount of time is spent in idle mode.During idle periods, the unit is normally stationary or on turning gear for some daily period.After the rotor is ambiently cooled during the nightly lows, the rotor will retain much of the lower temperature relative to the increasing ambient temperature and humidity during the day.As a result the rotor will sweat like cold drink on a warm day, and the deposits on the blades and vanes will be similarly affected.This is a common mechanism for deposit activation and corrosion that seems to be aggravated by the new paradigm of unit cycling.These are the periods where corrosive deposits combined with moisture will create conditions ideal for pitting, particularly if the airfoil deposits contain a substantial concentration of sulfur and chlorine-containing compounds.
Mitigation
Units may be waterwashed online each day when operated and the ambient temperature is greater than about 50°F.Offline water washing may be performed prior to performance testing or to restore lost capacity.In both cases the water washing is performed to provide performance benefits and also to prevent the accumulation of corrosive deposits.However, performing an online waterwash prior to operation does not remove the deposits accumulated during the subsequent operation cycle, nor does it remove much deposit beyond the second stage due to phase transition from liquid to vapor.Moreover, if the subsequent operation cycle is followed by a long idle period in humid weather, the deposits can absorb the ambient moisture and activate the corrodents.Off-line washes must be performed with demineralized water and a cleaning solution tailored to the deposits.Proper rinses with conductivity measurements taken at the drain ports are advised.Offline water washing is much more effective at removing compressor deposit accumulation, but proper drying is necessary to prevent pitting under remaining, tenacious deposits.
Figure 7. EDS Spectrum of compressor fouling deposits. Chlorides, sulfur deposits, and sodium deposits can be corrosive to stainless steels.
Another aspect of the operation that can affect the compressor deposits and moisture is proper sealing of the inlet filter house.All seams should be sealed with a weatherproof material and the fitment surfaces should be in good condition.Water leaks from the roof or any other area that causes standing water should be addressed.Additionally, corroded surfaces should be prepped and painted to stop the corrosion.Any bolts, nuts, and screws should be inspected for significant corrosion and potential loss of material that can become foreign object damage.
From a mitigation standpoint, two aspects must be addressed to reduce the susceptibility to pitting.First, the accumulation of deposits must be reduced.This may be achieved by higher efficiency filtration media (such as HEPA and hydrophobic Gore® Filters) and more aggressive offline water washing with a cleaning solution tailored to the deposits.Second, the presence of unwanted water must be reduced.Waterwashing should be followed by operation to ensure all moisture is evaporated.Water repelling filtration (such as Gore® filtration media) may reduce some of the water ingestion during wet weather, and may also prevent some of the influent from cooling tower drift (Gore® filtration medial is quite expensive, so a cost-benefit analysis may be require do to justify the additional expense).Long idle or layup periods should be combined with closure of the bellmouth and with a dry air source (heater or dehumidifier) to ensure that corrosive deposits are not activated.Mist eliminators and auto-close stack dampers are also beneficial, and should have some effect on reducing the ingress of moisture into the combustion turbine unit.
A detailed unit inspection may be advised, during which time deposit samples can be collected from the pre-filters, conical filters, and forward compressor blades / vanes / IGVs for corrosive species survey, as well as establishing the efficacy of the current filtration system.At this time, the severity of any pitting can also be documented.Additionally, mold replication can be performed on the LE of the forward compressor blades to gauge the severity of erosion channeling, which is often governed by OEM technical letters or service bulletins. A survey of the inlet filter house is also advised, where potential points of uncontrolled ingress can be identified.Additionally, the structure can be mapped for corrosion, cracked or damaged structures, and potential fastener liberation.
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.
https://www.structint.com/wp-content/uploads/2022/02/SI-Presentents-at-PRCI-AGA-ASME.jpg363668Structural Integrityhttps://www.structint.com/wp-content/uploads/2023/05/logo-name-4-930x191-1.pngStructural Integrity2022-02-18 18:36:502023-08-24 16:29:38Pipeline Integrity Activity and Plans for 2022
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 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).
https://www.structint.com/wp-content/uploads/2021/10/Material-Verification-for-Oil-and-Gas-Clients-Pipeline-Integrity-Solutions.jpg363668Structural Integrityhttps://www.structint.com/wp-content/uploads/2023/05/logo-name-4-930x191-1.pngStructural Integrity2021-10-06 18:23:322023-08-24 16:24:08News & Views, Volume 50 | Material Verification for Oil and Gas Clients
Initial introduction of many of the hydrogen fueling stations to support this rapidly growing demand were installed around 2010. There were many designs of cylinders developed and installed at that time, many with known limitations on the life of the equipment due to the high pressures involved and cyclic fatigue crack growth issues due to hydrogen embrittlement.The designs were often kept relatively simple to lower their costs often with little or no considerations for in-service inspection or potential end of life considerations.Others involved innovative designs with reinforcing wrapping to try to enhance the life of the vessels, but by doing so, these designs limited the access to the main cylinder wall for in-service inspection.
Many of these vessels are now reaching or passing the design life established by ASME.This is resulting in problems for operators of this equipment as some jurisdictions will not allow the vessels to operate beyond the design life without inspection or re-rating of the vessels to extend the fatigue life.SI’s FatiguePRO is a commercial software solution which has been addressing this exact concern for over 25 years.
The integrity of the nuclear reactor pressure vessel is critical to plant safety.A failure of the vessel is beyond the design basis.Therefore, the design requirements for vessels have significant margins to prevent brittle or ductile failure under all anticipated operating conditions.The early vessels in the U.S. were designed to meet Section VIII of the ASME Boiler and Pressure Vessel Code and later Section III.ASME Section III included requirements for more detailed design stress analyses also included a fracture mechanics approach to establish operating pressure-temperature heatup and cooldown curves and to assure adequate margins of safety against brittle or ductile failure incorporating the nil-ductility reference temperature index, RTNDT. This index is correlated to the material reference fracture toughness, KIC or KIa.
Radiation embrittlement is a known degradation mechanism in ferritic steels, and the beltline region of reactor pressure vessels is particularly susceptible to irradiation damage.To predict the level of embrittlement in a reactor pressure vessel, trend curve prediction methods are used for projecting the shift in RTNDT as a function of material chemistry and fluence at the vessel wall.Revision 2 of this Regulatory Guide is being used by all plants for predicting RTNDT shift in determining heatup and cooldown limits and hydrostatic test limits.
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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 or “Mega-Rule 1”.
The integrity of the nuclear reactor pressure vessel is critical to plant safety.