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

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OIL & GAS SAFETY & RELIABILITY

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

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

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

KEY ELEMENTS OF THE EVALUATION INCLUDE

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

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

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

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

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

 

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

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

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

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

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

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

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News & Views, Volume 52 | PEGASUS: Development for TRISO Fuel and Advanced Reactor Applications

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DEVELOPMENT FOR TRISO FUEL AND ADVANCED REACTOR APPLICATIONS

By:  Bill Lyon

The Pegasus code allows the user to develop more realistic models of fuel behavior by utilizing an innovative 3D framework that delivers a more detailed and rigorous solution. This solution allows the user to remove conservative assumptions, simplifications, and uncertainties resulting from 2D or 1D simplified/empirical solutions. 

Figure 1. A PEGASUS TRISO fuel particle model and mesh showing geometry and composition

Remove the conservativism and start using the calculated operational margins to increase efficiencies and reduce the capital outlay for refueling.

QUICK FACTS

  • Independently developed 3D FEM code; fuel vendor independent code provides best-estimate performance modeling
  • Focused on fuel structure
  • Provides high-fidelity results
  • Addresses existing fuel performance
  • Aids in the development of advanced fuel designs
  • Ready for Gen IV Reactors and TRISO Fuels

BENEFITS REALIZED

  • Reduced conservatism
  • Increased efficiencies
  • Potential for significant fuel cost savings

INTRODUCTION
The PEGASUS nuclear fuel behavior code is a robust 3D, finite element modeling (FEM) computational software platform capable of thermo-mechanical and structural non-linear analyses of nuclear fuel and reactor components. Focused initially on light water reactor (LWR) fuels and materials, PEGASUS is being adapted and applied to a broader range of emerging industry priorities for proposed Gen IV (Generation IV) advanced reactor designs such as high-temperature gas (HTGRs) and molten salt-cooled reactors (MSRs). These applications require modeling various fuel forms, geometries, and materials such as high assay, low enrichment uranium (HALEU), advanced cladding alloys, and other fuels with integrated containment such as tri-structural isotropic (TRISO) fuel particles and encapsulated particle fuel types. PEGASUS is perfectly positioned to evaluate these challenging structures with realistic modeling and simulation results.

TRISO-BASED FUELS AND MATERIALS DEVELOPMENT
One of the significant efforts underway in the continued development of PEGASUS is the introduction of material constitutive and behavioral models for TRISO fuel and the materials that comprise this fuel form. The initial research on the needed material property and behavior model data comes from a variety of sources, including the Department of Energy’s (DOE’s) Advanced Gas Reactor (AGR) fuel development and qualification experimental program [1] and numerous DOE-supported modeling efforts such as those from Hales et al. [2,3]. In parallel to those efforts, geometric modeling and meshing techniques specifically designed to address the complex TRISO fuel geometric configurations are being explored and developed. These exploit the CAD-like modeling environment and the already available automated meshing tools and capabilities in PEGASUS.

TRISO fuel forms are comprised of multi-layered particles embedded into fuel compacts of various compositions and shapes. The TRISO particle layers are designed to encapsulate and contain the nuclear fuel and the fission products produced during operation. It is this characteristic that creates the robust nature of TRISO-based fuels. The fuel particles are typically composed of a fuel kernel, such as uranium oxycarbide (UCO), surrounded by layers of 1) a porous carbon buffer, 2) an inner pyrolytic carbon (PyC) shell, 3) a silicon carbide (SiC) layer, and 4) an outer PyC shell. The orientation and relative thicknesses of these layers are shown in Figure 1, which depicts a basic PEGASUS TRISO particle model.

Material constitutive models have been developed for UCO fuel, porous and pyrolytic carbon, and SiC and are currently being tested for application in PEGASUS.

TRISO FUEL CONFIGURATIONS AND MODELING DEVELOPMENT
In addition to conventional FEM-based modeling and meshing capabilities, PEGASUS also contains several tools explicitly designed to facilitate advanced reactor and fuel analysis. These include: 1) a 3D and hybrid 2D/3D meshing capability to optimize computational efficiency (currently under development), 2) a “spherical mesh object” tool to generate 3D/2D spheres and embedded spheres for modeling TRISO and fully encapsulated TRISO fuel forms, and 3) a “spiral extrusion” tool which can generate complex, spiral 3D fuel geometries and meshes such as those required for helical multi-lobed advanced fuel designs.

The spherical mesh object and spiral extrusion tools are unique to PEGASUS and, to our knowledge, not found in any other fuel performance or general-purpose FEM code. 

Figure 2. Example TRISO particle distribution: (a) micrograph of a TRISO fuel compact (adapted from Nelson [5]), (b) random particle distribution pattern algorithm output.

Figure 3. Cross-sectional view of embedded TRISO particles in a 3D fuel compact matrix.

These modeling capabilities allow PEGASUS to be used to investigate very detailed mechanical and structural effects in highly complex fuel forms. For example, the mechanical interaction between TRISO fuel layers, including the effects of cracking, debonding, and asphericity, can be modeled explicitly. Future work is planned to integrate damage-mechanics modeling capability into PEGASUS that is specifically applicable to TRISO-based fuels.

Given the complexity of typical TRISO fuel forms, another critical aspect for analysis is the development of a consistent methodology for generating configurations that mimic the distribution of TRISO particles in a fuel matrix. A technique has been developed based on a “passive randomization method” originated by Sukharev [4] that yields distribution patterns approximating those of TRISO fuels observed during fuel examinations. An example of an early application of this technique is shown in Figure 2, which compares a fuel micrograph to a generated TRISO particle configuration pattern.

For application in PEGASUS, geometric configurations such as shown in Figure 2b are converted into 2D and 3D FEM meshes with TRISO kernels embedded in meshed substrates using automated tools. Models such as these can provide the bases for computational studies of TRISO fuel performance, from detailed kernel multilayer response to interactions between multiple kernels and their surrounding matrix. Several examples of TRISO meshes generated with PEGASUS are shown in Figures 3, 4, and 5. Figure 3 illustrates the cross-section of a 3D TRISO fuel compact with embedded TRISO particles. The appearance of multiple particle sizes is an indication of varying particle depths within the matrix. This figure was generated using the spherical object meshing tool in PEGASUS.

Figure 4. Cross section of an array of discrete 3D TRISO particles embedded into a graphite compact pellet.

A more complex 3D model of encapsulated TRISO particles is shown in Figure 4.  This model features a sparse particle distribution generated using the randomization technique applied in Figure 2b coupled with 3D automated meshing capabilities. This model was meshed in PEGASUS using an automated scripting tool and tested early in the development project using simplified approximations of thermal and mechanical properties of the kernel and matrix materials. Boundary conditions simulating prototypic gas reactor conditions were used in the simulation. Figure 5 shows the plotted temperature distribution from a portion of the model in figure 4.

Figure 5. Temperature distribution in a cross-section of a 3D slab of a TRISO compact matrix model under prototypic gas-cooled reactor conditions.

Further development of the TRISO fuel modeling capabilities in PEGASUS is ongoing. Detailed 3D modeling of TRISO kernels with irregular geometries such as non-uniform thicknesses and shapes in the pyrolytic carbon and SiC layers has been identified as a high priority as we advance. Additional priorities for future development include 1) implementation of mechanistically based, deterministic TRISO kernel and fuel compact failure models integrated into the material constitutive relations and 2) the calculation and tracking of fission product species diffusion and concentrations which incorporate the effects of chemical interactions, kernel layer, and substrate cracking.

SUMMARY
The PEGASUS nuclear fuel behavior code is an advanced, independently developed 3D FEM computational software program capable of conducting complex, coupled thermo-mechanical and structural non-linear analyses. The role of PEGASUS is envisioned as complementary to existing regulatory-based assessment and licensing tools, where there is a need to address conservatism, perform an independent assessment, or provide additional fidelity to laboratory-sponsored research where wider materials, phenomena, or fidelity is needed. Current development activity is focused on application to proposed GEN IV advanced reactor designs featuring unique fuel materials and design configurations such as TRISO-based ceramic fuels to be deployed in HTRGs and MSRs. Future development work on PEGASUS will continue along multiple avenues, emphasizing TRISO constitutive and deterministic failure model development, implementation, and modeling. In summary, PEGASUS provides high fidelity and independent advanced analysis capability that can be used to address existing fuel performance. It allows for less conservatism and accelerates the development, design, and regulatory processes for new fuel concepts and advanced fuel designs such as those employing TRISO-based fuels.

References

  1. D. A. PETTI, G. BELL, and the AGR Team, “The DOE Advanced Gas Reactor (AGR) Fuel Development and Qualification Program,” INEEL/CON-04-02416, 2005 International Congress on Advances in Nuclear Power Plants, May 15-19, 2005.
  2. J. D. HALES et al., “Multidimensional Multiphysics simulation of TRISO particle fuel,” J. Nucl. Mat. 443 (2013) 531-543.
  3.  J. D. HALES et al. “BISON TRISO Modeling Advancements and Validation to AGR-21 Data,” INL/EXT-20-59368, September 2020.
  4.  A. G. SUKHAREV, Optimal strategies of the search for an extremum, U.S.S.R. Computational Mathematics and Mathematical Physics, 11(4), 1971.
  5. A. T. NELSON, Features that Further Performance Limits of Nuclear Fuel Fabrication: Opportunities for Additive Manufacturing of Nuclear Fuels, ORNL/SPR-2019/1183, May 2019.

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News & Views, Volume 52 | Online Monitoring of HRSG with SIIQ™

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Figure 1. Typical components that are monitored with the pertinent damage mechanisms in mind.

A CASE STUDY ON IMPLEMENTATION AT A 3X1 COMBINED CYCLE FACILITY (ARTICLE 1 OF 3) 

By:  Kane Riggenbach and Ben Ruchte

SI has successfully implemented a real-time, online, damage monitoring system for the Heat Recovery Steam Generators (HRSGs) at a combined cycle plant with a 3×1 configuration (3 HRSGs providing steam to a single steam turbine).  The system is configured to quantify and monitor the life limiting effects of creep and fatigue at select locations on each of the HRSGs (e.g. attemperators, headers, and drums – see Figure 1).  The brand name for this system is SIIQ™, which exists as a monitoring solution for high energy piping (HEP) systems and/or HRSG pressure-part components.  SIIQ™ utilizes off-the-shelf sensors (e.g. surface-mounted thermocouples) and existing instrumentation (e.g. thermowells, pressure taps, flow transmitters, etc.) via secure access to the data historian.  The incorporation of this data into SI’s damage accumulation algorithms generates results that are then displayed within the online monitoring module of SI’s PlantTrack™ data management system (example of the dashboard display shown in Figure 2).  

Figure 2. Example dashboard of the health status and ‘action’ date for a variety of components.

This article will be part of a series discussing items such as the background for monitoring, implementation/monitoring location selection, and future results for the 3×1 combined cycle plant.  

  • Article 1 (current):  Introduction to SIIQ™ with common locations for monitoring within HRSGs (and sections of HEP systems)
  • Article 2: Process of SIIQ™ implementation for the 3×1 facility with a discussion of the technical foundation for damage tracking
  • Article 3: Presentation of results from at least 6+ months, or another appropriate timeframe, of online monitoring data

BASIS FOR MONITORING
The owner of the plant implemented the system with the desire of optimizing operations and maintenance expenses by reducing inspections or at least focusing inspections on the highest risk locations.  The system has been in place for a few months now and is continuously updating risk ranking of the equipment and ‘action’ intervals.  The ‘action’ recommended may be operational review, further analysis, or inspections.  This information is now being used to determine the optimum scope of work for the next maintenance outage based on the damage accumulated.  Like many combined cycle plants, attemperators are typically a problem area.  Through monitoring, however, it can be determined when temperature differential events occur and to what magnitude.  Armed with this information aides in root cause investigation but also, if no damage is recorded, may extend the inspection interval.

HRSG DAMAGE TRACKING
Many HRSG systems are susceptible to damage due to high temperatures and pressures as well as fluctuations and imbalances.  Attemperators have been a leading cause of damage accumulation (fatigue) through improper design/operation of the spray water stations (Figure 5).  In addition, periods of steady operation can result in accumulation of creep damage in header components (Figure 6) and unit cycling increases fatigue and creep-fatigue damage in stub/ terminal tubes and header ligaments (Figure 7).  Monitoring the damage allows equipment owners to be proactive in mitigating or avoiding further damage.

Traditionally, periodic nondestructive examinations (NDE) would be used to determine the extent of damage, but in HRSGs this can be challenging due to access restraints and, in the case of the creep strength enhanced ferritic (CSEF) materials such as Grade 91, damage detection sensitivity is somewhat limited until near end of life.  Continuous online monitoring and calculations of damage based on unit-specific finite element (FE) models (sometimes referred to as a ‘digital twin’) with live data addresses this issue.

Figure 4. Examples of damage observed by SI on attemperators.

Reliable life consumption estimates are made by applying SI’s algorithms for real-time creep and fatigue damage tracking, which use operating data, available information on material conditions, and actual component geometry.

Figure 5. Examples of creep damage observed by SI on header link pipe connections (olets).

SIIQ tracks trends in damage accumulation to intelligently guide life management decisions, such as the need for targeted inspections, or more detailed “off-line” analysis of anomalous conditions. This marks a quantum leap forward from decision making based on a schedule rather than on actual asset condition. 

Figure 6. Examples of creep/fatigue damage observed by SI at tube-to-header connections.

Figure 7. Examples of online monitoring alerts generated from SIIQ

SIIQ can be configured to provide email alerts (Figure 7) when certain absolute damage levels are reached, or when a certain damage accumulation over a defined time frame is exceeded. In this way, the system can run hands-off in the background, and notify maintenance personnel when action might be required.

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News & Views, Volume 52 | An SIIQ™ Primer

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POWER PLANT ASSET MANAGEMENT

SI’s technology differs from most systems by focusing on MODELING OF DAMAGE MECHANISMS (e.g. damage initiation and subsequent rate of accumulation) affecting components that, if a failure were to occur, would impact safety and reliability.

Figure 1. Typical architecture for connection to data historian.

SIIQ™ is part of the next-generation approach for managing assets through online monitoring and diagnostic (M&D) systems. The advancements in sensor technology, signal transmission (wired or wireless), data storage, and computing power allow for ever more cost-efficient collection and analysis of ‘Big Data.’ 

The online monitoring module of SI’s PlantTrack™ data management system can retrieve operating data from OSIsoft’s PI data historian (or other historians, for that matter – see above for typical architecture).  Access to data from the historian is critical for moving beyond the stage of detecting adverse temperature events from the local surface-mounted thermocouples.  Examination of pertinent data from select tags (as seen in Figure 3 of the article beginning page 29) is reviewed by SI experts to help derive a more optimal solution to mitigate further events.  The benefit of the real-time monitoring is to detect improper operation and diagnose prior to damage progressing to failure.  Continuously monitoring the condition allows for early remediation and potentially avoiding a failure that would result in loss of unit availability and possible personnel injury.  Further, if monitoring indicates no issues are occurring, it may justify deferring a costly inspection.

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Structural Integrity Associates | News and Views, Volume 51 | Optical Microscopy | Applications and Benefits

News & Views, Volume 51 | Optical Microscopy Applications and Benefits

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By:  Clark McDonald

In the world of metallurgical failure analysis, areas of interest on broken parts can be colorful or drab, three-dimensional or flat, and most importantly, very big or very small.  A big part of failure analysis work is telling the story, explaining the failure mode, or in some cases, showing that critical piece of evidence that explains why a metal component has failed.  From wide-angled lenses to extremely high magnification scanning electron microscope imagery, documentation of failed components is a big part of the presentation.  

In this edition of Structural Integrity’s Lab Corner, we wanted to provide some interesting content related to that middle-of-the-road region of magnification; closer than macro-photography but farther away than the 100X to 5000X magnifications that cover most of the applications requiring scanning electron microscopy.  In other words, the comfortable world of optical microscopy, where colors, shapes, and even surface textures are part of the story.  To do this, we’ve chosen some images that show the usefulness of quality optical microscopic documentation.  Each of the provided examples include a brief description along with specific comments on the benefits of optical microscopy for that project, where applicable.

Figure 1. Two- and three-dimensional color images of an aluminum annode plate showing light-colored deposits that have caused uneven wastage. The 3D image shows the extent of material removal in locations where deposits are not present. Normal wastage in this application should be uniform.

Figure 2. Two- and three-dimensional color images showing fastener thread flank damage and a crack origin near the root of the upper thread. The 3D image shows that the crack origin is located on the thread flank rather than at the deepest part of the thread root.

Figure 3. Two- and three-dimensional images of a copper heat exchanger tube that has been damaged from under-deposit corrosion (UDC). The image at left shows the typical appearance of the ID deposits. The center image shows a region of damage surrounding a pinhole leak. The 3D image provides an idea of the depth of internal corrosion in the tube.

Figure 4. Two- and three-dimensional images of a region of damage on an internal surface of a feedwater pump. The image at left shows the appearance of brownish deposits found within the corroded region of the pump surface. The 3D image provides an indication of the depth and shape of the corrosion damaged region.

Figure 5. Two dimensional stitched image of a weld cross section showing cracking emanating from a shallow weld root. Porosity is also visible in multiple locations in the weld.

Figure 6. Images of a region of damage on the exterior of a heat exchanger tube where wastage has occurred near the tube sheet. The upper right image is a view of the leak location with an overlay of lines showing the position where the surface profile was documented as well as the depth profile (overlaid and in the lower image). The upper left image, which has an appearance similar to an x-ray, is a side view of the 3D image of the tube surface.

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News & Views, Volume 51 | Drone Inspections

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SI EXPANDED CAPABILITIES

By:  Jason Van Velsor and Robert Chambers

Structural Integrity (SI) has recently added drones to our toolbox of inspection equipment. Using drones, inspectors are able to complete visual inspections safely and more efficiently. Applications of drones for visual inspections include plant and piping walkdowns, structural inspections and atmospheric corrosion monitoring (ACM) of exposed pipeline.

Figure 1. Drone image of a dent on an elevated section of pipeline

Pipe hanger walkdowns at fossil and combined cycle plants are part of a routine inspection process. During these inspections, the inspector is required to view and mark down pipe hanger positions and assess their condition. While some hangers provide easy access for the inspector, this is not always the case. Some of these may be located in elevated positions that require the plant to build out scaffolding, which not only increases the cost, but also can put the inspector at risk when working at elevation. With the use of drones, the inspector can fly up to the pipe hangers from a safe location and get a live high-resolution video feed from the camera mounted on the drone. Saving pictures and the video footage can also allow the inspector to go back and review the footage at a later time.

ACM is another example where drones have proven to be a useful tool. ACM inspections of outdoor above ground pipelines are typically done by

walking down the pipeline and recording any signs of atmospheric corrosion. There are many occasions where the pipeline will be elevated or cross over rivers and railroads, requiring scaffolding or fall protection. By using a drone to fly along the pipeline, the inspection can be completed much more efficiently and safely. In situations where a GPS signal is available, such as outdoor pipeline inspections, the GPS coordinates can be saved with each photo. Custom SI-developed software can then automatically compile the acquired images and create a KML file to be viewed in Google Earth, allowing the client to get an overview of the inspection results. 

Figure 2. Google Earth view of image locations

Moving forward, SI plans to utilize these drones for more than just visual inspections. Possible applications could include using drones to perform ultrasonic thickness testing or Structural Integrity Pulsed Eddy Current (SIPEC™) examinations. All of SI’s pilots in command hold valid FAA Part 107 certificates and pilot registered drones.

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Structural Integrity Associates | News and Views, Volume 51 | Pitting Corrosion in Conventional Fossil Boilers and Combined Cycle:HRSGs

News & Views, Volume 51 | Materials Lab Featured Damage Mechanism

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PITTING CORROSION IN CONVENTIONAL FOSSIL BOILERS AND COMBINED CYCLE/HRSGS

By:  Wendy Weiss

Pitting is a localized corrosion phenomenon in which a relatively small loss of metal can result in the catastrophic failure of a tube. Pitting can also be the precursor to other damage mechanisms, including corrosion fatigue and stress corrosion cracking. Pits often are small and may be filled with corrosion products or oxide, so that identification of the severity of pitting attack by visual examination can be difficult. 

Figure 1. Severe pitting in a tube from a package boiler

Mechanism 

Pitting is a localized corrosion attack involving dissolution of the tube metal surface in a small and well-defined area. Pitting corrosion can occur in any component in contact with water under stagnant oxygenated conditions. Pitting in economizer tubing is typically the result of poor shutdown practices that allow contact with highly-oxygenated, stagnant water. Pitting also may occur in waterwall tubing as a result of acidic attack stemming from an unsatisfactory chemical cleaning or acidic contamination. 

Pits that are associated with low pH conditions tend to be numerous and spaced fairly close together. The pits tend to be deep-walled compared to the length of the defect. A breakdown of the passive metal surface initiates the pitting process under stagnant oxygenated conditions. A large potential difference develops between the small area of the initiated active pit (anode) and the passive area around the pit (cathode). The pit will grow in the presence of a concentrated salt or acidic species. The metal ion salt (M+A-) combines with water and forms a metal hydroxide and a corresponding free acid (e.g., hydrochloric acid when chloride is present). Oxygen reduction at the cathode suppresses the corrosion around the edges of the pit, but inside the pit the rate of attack increases as the local environment within the pit becomes more acidic. In the event that the surfaces along the walls of the pit are not repassivated, the rate of pit growth will continue to increase since the reaction is no longer governed by the bulk fluid environment. Pitting is frequently encountered in stagnant conditions that allow the site initiation and concentration, allowing the attack to continue. 

The most common cause of pitting in steam touched tubing results from oxygen rich stagnant condensate formed during shutdown. Forced cooling and / or improper draining and venting of assemblies may result in the presence of excess moisture. The interface between the liquid and air is the area of highest susceptibility. Pitting can also be accelerated if conditions allow deposition of salts such as sodium sulfate that combine with moisture during shutdown. Volatile carryover is a function of drum pressure, while mechanical carryover can increase when operating with a high drum level or holes in the drum separators. Pitting due to the effects of sodium sulfate may occur in the reheater sections of conventional and HRSG units because the sulfate is less soluble and deposits on the internal surfaces. During shutdowns the moisture that forms then is more acidic. 

Figure 2. Pitting on the ID surface of a waterwall tube

Typical Locations

In conventional units, pitting occurs in areas where condensate can form and remain as liquid during shutdown if the assemblies are not properly vented, drained, or flushed out with air or inert gas. These areas include horizontal economizer tubes and at the bottom of pendant bends or at low points in sagging horizontal tubes in steam touched tubes. 

In HRSGs, damage occurs on surfaces of any component that is intentionally maintained wet during idle periods or is subject to either water retention due to incomplete draining or condensation during idle periods. 

Attack from improper chemical cleaning activities is typically intensified at weld heat affected zones or where deposits may have survived the cleaning. 

Features

Pits often are small in size and may be filled with corrosion products or oxide, so that identification of the severity of pitting attack by visual examination can be difficult. 

Damage to affected surfaces tends to be deep relative to pit width, such that the aspect ratio is a distinguishing feature. 

Root Causes

Figure 3. Pitting on the ID surface of an economizer tube

The primary factor that promotes pitting in boiler tubing is related to poor shutdown practices that allow the formation and persistence of stagnant, oxygenated water with no protective environment. Confirming the presence of stagnant water includes: 

  1. analysis of the corrosion products in and around the pit; 
  2. tube sampling in affected areas to determine the presence of localized corrosion; and 
  3. evaluation of shutdown procedures to verify that conditions promoting stagnant water exist. 

Carryover of sodium sulfate and deposition in the reheater may result in the formation of acidic solutions during unprotected shutdown and can result in pitting attack. Similarly flyash may be pulled into reheater tubing under vacuum and form an acidic environment.

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Structural Integrity Associates | News and Views, Volume 51 | Acoustic Emission Testing Streamlining Requalification of Heavy Lift Equipment

News & Views, Volume 51 | Acoustic Emission Testing

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STREAMLINING REQUALIFICATION OF HEAVY LIFT EQUIPMENT

By:  Mike Battaglia and Jason Van Velsor

Structural Integrity Associates | News and Views, Volume 51 | Acoustic Emission Testing Streamlining Requalification of Heavy Lift Equipment

Figure 1. Heavy lift rig attached to reactor head in preparation for removal.

BACKGROUND
Proper control of heavy loads is critical in any industrial application as faulty equipment or practices can have severe consequences.  The lifting technique, equipment, and operator qualifications must all meet or exceed applicable standards to ensure industrial safety.  The significance of heavy lifts at commercial nuclear facilities is, perhaps, even greater.  In addition to the consequences of an adverse event that are common to any industry (bodily injury or human fatality, equipment damage, etc.), the nuclear industry adds additional challenges.  Such an adverse event in the nuclear industry can also affect (depending on the specific lift) fuel geometry / criticality, system shutdown capability, damage to safety systems, etc.  One example of a critical lift in nuclear power facilities is the reactor vessel head / reactor internals lift.  

The requirement to inspect the heavy lifting equipment for structural integrity is prescribed in NUREG-0612, Control of Heavy Loads At Nuclear Power Plants, as enforced by NRC Generic Letter 81-07. The aforementioned NUREG document describes specific requirements for special lifting devices.  The requirements prescribed include: 

  • Special lifting devices are subject to 1.5X rates load followed by visual inspection, or
  • Dimensional testing and non-destructive examination (NDE) of the load bearing welds

In the case of the former requirement, it can be difficult or even dangerous to test these lift rigs, which are designed to carry over 150 tons, at a factor of 1.5x.  In the case of the latter requirement, employing the more traditional NDE techniques of MT, PT, and UT to inspect the lift rigs can be costly (both in terms of labor and radiological dose) and time consuming, in terms of impact to outage critical path, depending on when the inspection is performed.  In PWRs or BWRs, inspections are performed in the reactor containment, or radiation-controlled area, and are typically only performed during the outage.   

Ultimately, the NRC requires licensees to determine how they will comply with the NUREG requirements.  One method that has been adopted (primarily by PWR plants) is Acoustic Emission (AE) testing.  AE testing is a non-destructive testing process that uses high-frequency sensors to detect structure-borne sound emissions from the material or structure when under load.  The process detects these acoustic emission events and, based on sensor locations and the known sound velocity and attenuation, can identify the approximate location of the sources or areas of concern.  If such areas are identified, based on analysis of the data captured under load, those areas must be further investigated to characterize the indication.  Such additional techniques may include surface examination (MT or PT), or volumetric UT to precisely locate, characterize, and size any indications.  

Employing an advanced technique such as AE can significantly reduce the time required to perform this evolution, also reducing both the cost and dose associated with meeting the NUREG requirements.  

The original deployment of this method was championed by a utility in the mid-1980’s and has since been adopted by many of PWR plants as the preferred inspection method.  

APPLICATION OF AE TESTING
In 2021, SI began offering AE testing services for reactor head lift rigs, including the qualified personnel, equipment, and tooling necessary to perform this work.  Our first implementation was at a nuclear plant in the Southeast US in the fall of 2021, and additional implementations are contracted in the spring and fall of 2022, and beyond.  

There are several advantages to AE testing that make it uniquely suited for the vessel head (or internals) lift application.  First, AE is a very sensitive technique, capable of picking up emissions from anomalies that cannot be detected by traditional techniques.  This allows for identifying areas of potential / future concern before they are an imminent safety danger.  Second, AE sensors are capable of sensing relevant emissions from a reasonable distance (up to 10 ft or more) between source emission and sensor placement.  As such, AE testing can monitor the entire lifting structure with a reasonable number of sensors (typically less than 20) placed on the structure.  Thus, sensors are strategically placed on the structure where failure is most likely – i.e., the mechanical or welded connections (joints) between structural members.  

This strategic sensor placement has another inherent advantage unique to the AE process.  If an indication is noted, the system has the capability to isolate the approximate source location (generally within a few inches) of the emission.  This is accomplished using a calculation that considers the arrival time and intensity of the acoustic emission at multiple sensor locations.  This is very beneficial when an indication requiring subsequent traditional NDE is noted as specific areas can be targeted, minimizing the scope of subsequent examinations.  

The ability of AE testing to rapidly screen the entire lift structure for active damage growth saves time and money over the traditional load testing and comprehensive NDE approaches.   

Figure 2. Lift rig turnbuckle outfitted with AE sensor.

Finally, and perhaps most importantly, the test duration is minimal and is, effectively, part of the standard process for reactor vessel head removal.  Sensor placement is performed during the normal window of plant cooldown and vessel head de-tensioning, so outage critical path is not compromised.  The actual test itself is performed as part of the head (or internals) lift; that is, when the head breaks from the vessel flange (and maximum load is achieved), the load is held in place for 10 minutes while monitoring for and recording acoustic emission activity.  Each sensor (channel) is analyzed during the hold period and a determination is immediately made at the end of the 10-minute period as to whether the lifting rig structure is suitable for use.  Unless evidence of an imminent failure is observed, the lift immediately proceeds to the head (or internals) stand.  The gathered data are also analyzed on a graded basis.  Depending on the energy intensity of the events detected at each sensor, subsequent recommendations may range from:  ‘Good-as-is’, to ‘recommend follow-up NDE post-outage’. 

The basic process of implementation is:

  • Calibrate and test equipment offsite (factory acceptance testing)
  • Mount sensors and parametric instrumentation (strain gauges, impactors) during plant cooldown and de-tensioning
  • System check (Pencil Lead Breaks (PLBs), and impactor test)
  • Lift head to the point of maximum load
  • Hold for 10 minutes
  • Continue lift to stand (unless evidence of imminent failure is observed)
  • Final analysis / recommendations (off line, for post-outage consideration)

SI VALUE ADD
During our fall 2021 implementation, SI introduced several specific process improvements over  what has been historically performed.  These advances have enhanced the process from both a quality and schedule perspective.  A few of these enhancements are:

COMMERCIAL GRADE DEDICATION OF THE SYSTEM
SI developed and deployed a commercial grade dedication process for the system and sensors.  Often, licensees procure this work as safety-related, meaning the requirements of 10CFR50 Appendix B apply.  The sensors and processing unit are commercially manufactured by a select few manufacturers that typically do not have QA programs that satisfy the requirements of 10CFR50, Appendix B. For this reason, SI developed a set of critical characteristics (sensor response, channel response to a simulated transient, etc.) and corresponding tests to validate that the system components are responding as-expected and can be adequately deployed in a safety-related application. 

Figure 3. Close-up of AE sensor.

EMPLOYING STRAIN GAUGES FOR MAXIMUM LOAD
The arrival time of an acoustic emission at one of the installed sensors is measured in milliseconds. For this reason, it is critical to initiate the 10-minute hold period precisely when peak load is reached. The historical method for synchronizing peak-load with the start of the hold period relied on the use of a stop-watch and video feed of the readout from the containment polar crane load cell.  When the load cell appears to max out, the time is noted and marked as the commencement of the test.  This approach can be non-conservative from a post-test analysis perspective as the data before the noted start time is typically not considered in the analysis. As the strain gauge correlation provides a much more precise point of maximum load that is directly synchronized with the data acquisition instrument, it is more likely that early acoustic emissions, which are often the most intense and most relevant, are correctly considered in the analysis.

REMOTELY ACTUATED IMPACTORS
One of the methods used in AE testing to ensure that the sensors are properly coupled and connected is a spring-loaded center punch test.  This test employs a center punch to strike the component surface, resulting in an intense sound wave that is picked up by all the sensors.  However, this test has historically been performed manually and required someone to physically approach and touch the lifting equipment.  In certain applications, this can be a safety or radiological dose issue and, additionally, can add time to an already time-critical plant operation.  For this reason, SI has introduced the use of remotely actuated impactors to perform this function. The result is equivalent but entirely eliminates the need to have personnel on the lift equipment for the test as this task is performed remotely and safely from a parametric control center.

Figure 4. Strain gauge output showing precise timing of peak load on lift rig.

CONCLUSION
Employing cutting-edge AE testing for your vessel head / internals heavy lift can save outage critical path time, reduce radiological dose, and identify structural concerns early in the process.  All of this leads to inherently safer, more efficient verification of heavy lift equipment.   

SI has the tools, expertise, and technology to apply cutting-edge AE testing to your heavy lifts.  SI is committed to continually improving the process at every implementation.  Improvements in software processing time, and setup / preparation time are currently in-process.  Finally, other potential applications for the method are also possible, and we stand ready to apply to the benefit of our clients.

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Structural Integrity Associates | News and Views, Volume 51 | Turbine Unit Trip and Event

News & Views, Volume 51 | Turbine Unit Trip and Event

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Recovery Best Practices

By:  Dan Tragresser

When a unit trips or experiences an event, the site will incur costs associated with the loss in production and regulatory penalties. Based on the severity, the outage scope may include hardware replacement and, if applicable, the purchase of make-up power. These costs can quickly drive the decision to make the return to service the only priority.

Structural Integrity Associates | News and Views, Volume 51 | Turbine Unit Trip and EventWith the reduction in staffing at power plants over the past 2 decades, many traditionally routine engineering and maintenance tasks have fallen by the wayside.  With limited resources, operations and engineering personnel must focus their time and efforts based on priority.  Quite often, keeping a unit online or quickly returning a unit to service will take priority over continuous improvement actions such as investigations and root cause analysis.

When a unit trips or experiences an event, the site will incur costs associated with the loss in production and regulatory penalties. Based on the severity, the outage scope may include hardware replacement and, if applicable, the purchase of make-up power. These costs can quickly drive the decision to make the return to service the only priority. Unfortunately, the review of event operational data, event precursors, and the collecting evidence through the unit disassembly very often falls below the priority of returning to service.  Collecting or re-creating evidence after the fact is nearly impossible.  This lack of priority often results in a lack of understanding of the root cause of the trip or event.  

Within large, complex plants and turbomachinery, trips or minor events are common but are rarely isolated, one-off events.  Many trips and events are repetitive in nature and, worse, are early indications of a more serious event to come.  While the cost of delays in returning to service may be high, the cost of not solving the root cause may be orders of magnitude higher, particularly if a failure event happens a second time.

Focusing on unit trips, best practices include:

  • Hold regular, cross-functional trip reviews.
  • If available, consider holding reviews across similar sites within a parent company.
    • Utilize knowledge and solutions that may already have been developed.
  • Trend trip events and frequency over a 1-to-3-year period.
    • Measure the success of prior projects based on the reduction of occurrences or elimination over a multi-year period.
    • Trips may be seasonal in nature, and re-occurrence may span timeframes greater than one year.
  • Review each trip as a near miss and assess potential consequences that may not have occurred this time.
  • Consider including trip investigation in site or corporate level procedures and celebrate successes.

Turbine Blade Failure

Focusing on unit events, the cost of an event requiring an outage and hardware replacement, not including make-up power purchase, can very quickly escalate to millions of dollars.  Compare that cost to the cost of a dedicated, independent resource for the duration of time required to perform a comprehensive investigation.  Also, consider the cost of the investigation versus the cost of reoccurrence or a similar event with more serious consequences.  The cost of the resource and investigation will almost always be in the noise of the overall cost.  Best practices include:

  • In nearly all cases, site and outage resources will be dedicated to the speedy rehabilitation of the unit.
    • Critical evidence is often lost or destroyed, unintentionally, based on the need to return to service quickly.
    • A dedicated, independent resource provides the best option to ensure that useful evidence is collected.
  • Assign a dedicated, independent resource to collect and review data and findings.
    • If a site resource is not available, borrow from a sister site or corporate team, ideally someone with an outside perspective and not necessarily an expert in the field.
    • Consider an external independent resource such as an industry consultant.
    • It will likely require a team to complete the overall root cause analysis, however, the likelihood of success will be much greater with facts and details being collected by a dedicated resource.
  • Initial steps as a dedicated, independent resource:
    • Ensure a controller and DCS data and alarm logs backup is completed before they time out.
    • Interview individuals that were on site at the time of the event and or in the days prior.
    • There is no such thing as too many pictures. It is common to find a critical link or detail in the background of a picture taken for another reason.
    • Clearly articulate hold points at which the independent resource will require inspections or data collection through the disassembly process.
    • Collect and preserve samples and evidence.
  • Where available, utilize other fleet assets to enable a detailed causal analysis with corrective and preventative actions.
    • Demonstrating a commitment to fleet risk reduction can minimize impacts with regulators and insurers.
  • Once an event occurs, those limited resources will be fully occupied. Creating a plan at this point is too late.
    • Discuss including the cost of an investigation into an event insurance claim with site insurers and what their expectations would be to cover the cost.
    • Maintain a list of resources, internal and external, to call upon as dedicated, independent resources.

Identifying the root cause of an event might be cumbersome, but far less cumbersome than dealing with the same type of event on a recurring basis.

Structural Integrity has team members and laboratory facilities available to support event investigations and to act as independent consultants on an emergent basis.

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