ML25183A334
| ML25183A334 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 06/21/2025 |
| From: | Dennis Galvin Plant Licensing Branch III |
| To: | Blind A - No Known Affiliation |
| Wall S | |
| References | |
| OEDO-25-00290, 2.206 Petition Suppl 2 | |
| Download: ML25183A334 (1) | |
Text
From: Alan Blind <a.alan.blind@gmail.com>
Sent: Saturday, June 21, 2025 12:05 PM To: Petition Resource <Petition.Resource@nrc.gov>
Cc: Natreon Jordan <Natreon.Jordan@nrc.gov>; PalisadesRestartProject
<PalisadesRestartProject.Resource@nrc.gov>; Jack Giessner <John.Giessner@nrc.gov>
Subject:
[External_Sender] Supplement to 2.206 Petition - Submission of SGTR Reference Paper on Tube R73C94 and Associated Accident Consequences
Subject:
Supplement to 2.206 Petition - Submission of SGTR Reference Paper on Tube R73C94 and Associated Accident Consequences Plant: Palisades, Docket: 05000255 To:
The Executive Director for Operations U.S. Nuclear Regulatory Commission (NRC)
Washington, DC From:
Alan Blind 1000 West Shawnee Road Baroda, Michigan 49101 Email: a.alan.blind@gmail.com
Dear Executive Director for Operations,
I am writing to formally submit the attached document, SGTR Reference Paper, as supplemental information supporting my 10 CFR 2.206 petition filed on May 16, 2025, titled:
Request for Enforcement Action Against Palisades Nuclear Plant for Violation of Technical Specification 3.4.17 Prior to Certified Shutdown, and for NRC to Require Compliance with This Condition Action Statement Before Restart.
This Reference Paper should be added to the docket as supporting analysis and documentation for my original 2.206 petition. It includes my evaluation of the Palisades Steam Generator Tube Inspection Report (ML24267A296), the SGTR accident analysis presented in FSAR Revision 36 (ML21125A341) with calculated dose at the site boundary, and applicable Emergency Plan classification and protective action requirements (ML24122C666).
Purpose and Key Findings of the SGTR Reference Paper
The attached analysis demonstrates the importance of completing a detailed Operational Assessment (OA), especially given that a single steam generator tubeTube R73C94was found in October 2024 to be dangerously close to structural failure and would have likely meet all the worst case condition used in the Chapter 14 accident analysis.
Key findings include:
Accident Dose Consequence: Holtecs licensing basis Steam Generator Tube Rupture (SGTR) analysis projects a Total Effective Dose Equivalent (TEDE) of 1.17 REM at the site boundary. Although this is below the 2.5 REM regulatory limit, it exceeds the 1.0 REM EPA Protective Action Guideline (PAG), which under FEMA/NRC protocols would require evacuation of homes within the Emergency Planning Zone (EPZ).
Tube R73C94 Near-Failure Condition: Based on the inspection data, Tube R73C94 had a 1.71-inch axial ODSCC crack with 73% through-wall depth at a tube support.
Applying industry-accepted crack growth rates and accounting for nonlinear hoop stress escalation as the remaining wall ligament thins, the evaluation concluded that tube failure would have occurred within approximately 4.5 months under continued full-power operation. This is a conceptual evaluation and does not include all of the factors of a full condition evaluation as per EPRI guidelines.
Invalidity of Leak-Before-Break Assumptions: The morphology and location of the crackadjacent to a tube support plateseverely limits early leakage detection, invalidating leak-before-break assumptions. As such, the risk of sudden rupture without detectable precursor leakage is elevated, reinforcing the need for rigorous backward and forward-looking assessments.
Two Regulatory Imperatives Based on the Reference Paper
- 1. Condition Monitoring Evaluation for Cycle 28: Holtec or Entergy, must complete a formal Condition Monitoring Assessment looking back on Entergys final operating cycle, applying the EPRI Steam Generator Integrity Assessment Guidelines (Rev. 3, 2011).
Factors to be considered include:
o Nondestructive examination (NDE) uncertainty o
Inspection technique capabilities o
Sizing error distributions o
Tube-to-tube variability o
Crack morphology and growth rate modeling o
Probability of detection and missed indications
- 2. Based on this comprehensive condition evaluation, it is highly likely that Tube R73C94 alone would constitute a White-level (or higher) finding under the NRCs Significance Determination Process (SDP), due to Entergys failure to performor failure to properly performan operational assessment for its last cycle of power operations, consistent
with applicable regulatory and industry standards. It also points to a potential broader range of uncertainties in condition monitoring factors, then previously used (see item 3).
- 3. Full Operational Assessment Prior to Restart: Holtec must also conduct a forward-looking Operational Assessment using a broad range of uncertainties, as prescribed in the same EPRI guidance. This should include:
o Bounding analysis for all degradation mechanisms o
Combined effect of flaw morphology and structural limits o
Sensitivity analysis of NDE limitations and crack growth variability o
Statistical confidence intervals across the inspection interval o
Compliance demonstration for structural and leakage integrity over the next full operating cycle Why This Matters More at Palisades Palisades is unique in two respects:
Venting of Radioactive Steam to the Environment, Is the Design Basis: Palisades designcarried forward, as proposed by Holtec, in FSAR Revision 36relies on direct atmospheric release of SGTR steam through the atmospheric dump valves. The plants turbine bypass valve (singular) is rated for only 5% of total steam flow, meaning that the majority of steam must be discharged through either the code safety valves or atmospheric dump valves. As a result, radioactive iodine releases are unavoidable during an SGTR event under the plants proposed licensed design (FSAR rev 36).
Emergency Plan Escalation Triggered by Dose Exceedance: Under NUREG-0654 and 10 CFR 50.47 guidance, the projected 1.17 REM TEDE triggers a General Emergency under EAL RA3.1, requiring homeowners evacuation orders from the Michigan Governor.
For these reasons, I respectfully request that this SGTR Reference Paper be added to the record for my 2.206 petition and be considered in the NRCs review of Holtecs proposed restart.
Thank you for your continued attention to this critical safety matter.
Sincerely, Alan Blind 1000 West Shawnee Road Baroda, Michigan 49101 Email: a.alan.blind@gmail.com
Attachment:
SGTR Reference Paper.pdf
Steam Generator Tube R73C94: What It Tells Us About Risk, Radiation, and the Emergency Plan at Palisades By Alan Blind, Former Vice President of Nuclear Operations, Indian Point Summary This report reviews the most serious steam generator tube defect identi"ed at the Palisades Nuclear Plant during recent inspections conducted by Holtec. Tube R73C94 was found to have a 1.71-inch axial outer diameter stress corrosion crack with 73% through-wall penetration. Based on conservative industry data and applicable NRC guidelines, this crack was at imminent risk of sudden, high-energy failure, with an estimated time-to-failure of 4.5 months or less, under full power operation. This analysis only considers normal operating stresses and does not consider the much higher stresses from other accidents, such as a Steam Line Break.
The "ndings presented here are based on Holtecs publicly submitted licensing documents and safety analyses, as well as U.S. Nuclear Regulatory Commission (NRC) guidance for evaluating steam generator tube integrity. The purpose of this report is to explain what these results mean for local residents, how the plants Emergency Plan would function in the event of a tube rupture, and why prompt public awareness is essential.
Understanding Tube R73C94 Steam generator tubes are one of the critical safety barriers in a nuclear plant, separating radioactive coolant in the reactor from the water that turns to steam and drives turbines. At Palisades, each steam generator has over 8,000 tubes made of Alloy 600a material known to be susceptible to stress corrosion cracking after long exposure to stress and chemical deposits.
During Holtecs 2024 inspections, Tube R73C94 was identi"ed as the most degraded and stood out with its long axial and deep penetration crack. It exhibited a 73% through-wall axial crack, 1.7 inches long, located at a tube support plate a known site for corrosion and "ow stagnation. According to standard
engineering practice and industry data (e.g., EPRI and NUREG/CR-6674), axial Outer Diameter Stress Corrosion Cracking (ODSCC) can grow at rates of 0.03 inches/year.
Based on this rate:
Wall thickness: 0.042 inches Crack depth: 73% = 0.0307 inches Remaining ligament: 0.0113 inches Crack growth rate: 0.0025 inches/month Time to full wall penetration: 4.5 months or less Importantly, as wall thickness diminishes, hoop stress rises non-linearly, accelerating the likelihood of burst failure. This means the crack was not just seriousit was entering a critical zone where failure becomes unpredictable and rapid.
What Kind of Failure Was Expected?
A tube rupture caused by axial ODSCC would result in a sudden burst failure, releasing pressurized radioactive coolant into the secondary side. At Palisades, that steam by design is vented through atmospheric dump valves, bypassing containment and releasing radioactive iodine-131 aerosols to the environment.
Unlike in newer plants, Palisades lacks dedicated steam containment features (e.g.,
high capacity steam dump to the condenser hotwells ) to prevent I-131 release. As a result, even a single tube rupture could lead to an uncontrolled radiological event.
Why This Tube Would Not Leak First Some equipment is designed to leak before it failsgiving operators time to intervene. In this case, however: Leak-Before-Break is Unlikely.
Due to the high crack length and depth, there was minimal opportunity for
detection via small leaks before full rupture. This conclusion is consistent with NRC guidance in NUREG-2195, and Holtec has made no showing that this tube or similar cracks would allow early leak detection.
What Happens If the Tube Fails?
If a tube rupture happens at Palisades, the Emergency Plan would be activated.
Holtec has proposed an updated Emergency Plan in its license amendment requests, and the structure of the response would follow NRC guidance in 10 CFR 50.47, Appendix E, and NUREG-0654/FEMA-REP-1.
Heres how it works:
1.
Event Classi"cation:
The plant would classify the event as a General Emergency under Emergency Action Level (EAL) RA3.1, which applies when two "ssion product barriers are lostin this case, the tube and containment.
2.
Noti"cation:
Within 15 minutes, the plant must notify state and county of"cials and recommend protective actions based on dose projections.
3.
Evacuation Recommendation:
If plume models show that projected dose to the public exceeds 1 rem TEDE (Total Effective Dose Equivalent), the licensee must recommend evacuation of affected downwind sectors.
4.
Governor's Role:
The State of Michiganthrough the governor or emergency manager would then issue a formal evacuation order, likely affecting areas within the 10-mile Emergency Planning Zone.
In Holtecs licensing basis, a steam generator tube rupture could result in a 1.17 rem TEDE dose at the site boundaryabove the evacuation threshold of 2.5 TEDE.
Comparison to My Experience at Indian Point In 2000, while serving as VP of Nuclear Operations at Indian Point, we experienced a steam generator tube rupture. Our plant design included a large condenser steam dump system, and successfully captured all radioactive material.
We declared a Site Area Emergencyone level below a General Emergency because no radioactive material reached the environment.
At Palisades, the same failure would result in a General Emergency because containment is not credited. The absence of modern design features increases the likelihood of an offsite release and requires immediate public protective action.
==
Conclusion:==
Why This Matters Now Tube R73C94 was removed from service and plugged, but it tells us more than just one inspection result. It demonstrates how aging infrastructure, limited containment features, and outdated design increase risk at Palisades. Had the plant been operating, that tube may have failed with no warning leak, triggering a radiological release and an evacuation order within minutes.
The Emergency Plan is designed to protect the publicbut only if its fully understood, fully resourced, and activated promptly. This report is intended to help local residents understand the seriousness of the issue, the response mechanisms in place, and why regulatory decisions about restarting Palisades must be made with full transparency and accountability.
- 1. Palisades Final Safety Analysis Report (FSAR) - Chapter 14 Source: NRC ADAMS Accession No. ML21125A338 Table 14.1-6 details radiological consequences for Chapter 14 accident scenarios, including SGTR.
Key Result:
1.17 rem TEDE at the Exclusion Area Boundary (EAB) for the iodine spike case.
0.2 rem TEDE for the Low Population Zone (LPZ).
Indicates offsite radiological impact under worst-case conditions modeled by Holtec.
- 2. Holtec Emergency Plan License Amendment Request (EP LAR)
Source: NRC ADAMS Accession No. ML24122C666 Emergency Action Level (EAL) RA3.1 is triggered in an SGTR scenario involving:
Loss of the Primary Coolant System (PCS) barrier.
Release to the environment via Atmospheric Dump Valves, breaching containment.
These conditions escalate the event to a General Emergency, the highest NRC emergency classi"cation.
- 3. Emergency Response and Protective Action Guidelines Under 10 CFR 50.47 and Appendix E to Part 50, a General Emergency requires:
15-minute noti"cation to offsite of"cials.
Protective Action Recommendations (PARs), such as evacuation, based on projected public dose.
The federal threshold for evacuation is 1 rem TEDE, which the Palisades accident analysis exceeds at the site boundary.
The planning basis uses guidance from NUREG-0654/FEMA-REP-1 and the EPA Protective Action Guides (PAGs).
Purpose of the Compilation This PDF package supports a comprehensive understanding of:
How Palisades differs from newer designs in SGTR containment capability.
What federal and plant-level emergency actions are required if a rupture occurs.
The regulatory basis for offsite protective actions, especially evacuation orders tied to iodine-131 release and public health risk.
Evaluation of Tube R73C94: Imminent Failure Risk in Palisades Steam Generator ML24267A296, PALISADES NUCLEAR PLANT -
SUMMARY
OF CONFERENCE CALL REGARDING STEAM GENERATOR TUBE INSPECTIONS (EPID L-2024-NFO-0008)
Evaluation of Tube R73C94: Imminent Failure Risk in Palisades Steam Generator Summary This evaluation determined that Steam Generator tube R73C94 at Palisades was at imminent risk of total failure. Inspection data revealed a 1.71-inch axial outer diameter stress corrosion crack (ODSCC) with 73% through-wall depth conditions that signi"cantly compromised the tube's structural integrity. Based on industry-established crack growth rates and the non-linear intensi"cation of hoop stress as the remaining wall thickness diminishes, the ligament in R73C94 would likely have failed within approximately 4.5 monthsor soonerunder continued full-power operation. As the crack approached full penetration, the sharply increasing local stresses indicated that structural failure was imminent, most likely resulting in a sudden, high-energy steam generator tube rupture (SGTR) without any meaningful leak-before-break warning.
Importantly, the crack morphology and depth indicate that the failure would most likely have occurred without any prior warning or detectable leakage. The tubes geometry and location at a tube support plate (TSP) would have limited early leakage detection, and standard leak-before-break assumptions do not apply. The most probable failure mode would have been a sudden, circumferential rupture posing a serious challenge for operator intervention and emergency response.
Background
Palisades uses two Combustion Engineering Model 2530 replacement steam generators, each with 8,219 Alloy 600 mill-annealed tubes (0.75" OD, 0.042" wall thickness). These tubes are supported by stainless steel eggcrate-type tube support plates (TSPs) and expanded through the tubesheet. Alloy 600 is known to be susceptible to stress corrosion cracking (SCC), particularly under the conditions present in the crevice regions near TSPs.
The NRC special report (ML24267A296) identi"ed multiple indications of axial ODSCC at TSP locations. Tube R73C94 exhibited the most severe degradation: a 1.27V voltage indication, 1.71-inch crack length, and 73% wall penetration.
Failure Mechanics and Stress Environment Stress Orientation and Crack Growth Hoop (circumferential) stress is the dominant stress in thin-wall, pressurized tubes and acts perpendicular to axial cracks. Axial ODSCC forms along the tube axis due to stress concentration, stagnant chemistry, and thermal conditions near the TSP.
In R73C94, the crack approached 3/4 through-wall depth. As the wall thins, remaining ligament stresses increase non-linearly, leading to imminent structural failure.
Likely Failure Characteristics Burst-Type Rupture: Failure would occur rapidly, resulting in a loud, high-pressure rupture. Though the crack is axial, the "nal rupture would be circumferential due to internal pressure acting radially.
Leak-Before-Break (LBB) Unlikely: The high crack length and depth offer minimal opportunity for detection via small leaks before full rupture. LBB assumptions are not applicable.
TSP Effects: Crack was at TSP H01-0.4. Tube support could obscure leak detection and contribute to a redirected rupture path.
Time-to-Failure Estimate Using conservative assumptions, the crack would grow from 73% to 100%
through-wall in ~0.38 years (4.5 months). See Appendix A for the crack growth model and reference data.
Expanded Context: Operational Assessment Considerations
While our analysis illustrates the proximity of Tube R73C94 to failure based solely on degradation depth and crack growth rate, a complete Operational Assessment (OA) as required by EPRI SG Integrity Assessment Guidelines (Rev. 3) and NEI 97-06 must consider a broader set of factors. These include NDE detection and sizing uncertainties, inspection coverage, accident-induced leakage performance, multiple degradation mechanisms, and the impact of material variability and outliers. The OA must also demonstrate compliance with structural and leakage criteria over the full inspection interval and account for any mitigative actions. Our simpli"ed model serves only as an illustration and does not substitute for the comprehensive forward-looking OA required under the EPRI framework.
Appendix A: Crack Growth Rate Assumptions and Time-to-Failure Estimate A time-to-failure estimate for Tube R73C94 was calculated using a conservative axial outer diameter stress corrosion cracking (ODSCC) growth rate of 0.03 inches per year. This rate is informed by industry practice and intended solely to illustrate how close this tube may have been to structural failure under continued operation.
It is not presented as a predictive model but as a bounding analysis using accepted assumptions.
Although the underlying benchmarking data is proprietary, the EPRI Steam Generator Integrity Assessment Guidelines (Rev. 3, 2011) have been cited in publicly available documents as recommending a default axial crack growth rate of 0.03 inches per year when plant-speci"c data is not available. This assumption is particularly applicable to Alloy 600 mill-annealed tubing exhibiting axial ODSCC degradation at tube support plate (TSP) locations.
Illustrative Time-to-Failure Calculation for Tube R73C94 Tube wall thickness = 0.042 inches Crack depth = 73% of 0.042" = 0.0307 inches Remaining ligament = 0.042" 0.0307" = 0.0113 inches Growth rate = 0.03 inches/year = 0.0025 inches/month
Time to 100% through-wall = 0.0113" ÷ 0.0025"/month 4.5 months This estimate does not account for the non-linear stress intensi"cation that occurs as the remaining ligament thins, particularly due to hoop stress concentrations.
Therefore, this 4.5-month estimate represents a bounding upper limit. Failure could plausibly occur sooner under actual plant conditions.
Conclusion Tube R73C94 was approaching structural failure with insuf"cient margin for detection or intervention. Based on referenced industry assumptions, failure would likely have occurred within approximately 4.5 months of continued operationor sooner.
FSAR CHAPTER 14 - SAFETY ANALYSIS Steam Generator Tube Rupture ML21125A341
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-1 of 14.15-10 14.15 STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF OFFSITE POWER 14.15.1 EVENT DESCRIPTION The steam generator tube rupture (SGTR) accident is a penetration of the barrier between the primary coolant system (PCS) and the main steam system which results from the failure of a steam generator U-tube. Integrity of the barrier between the PCS and the main steam system is significant from a radiological release standpoint. The radioactivity from the leaking steam generator tube mixes with the shell-side water in the affected steam generator. Following a reactor trip and turbine trip, the radioactive fluid is released through the steam generator safety or atmospheric dump valves as a result of the loss of normal AC power.
An SGTR event results in a depressurization of the PCS, causing a Thermal Margin/Low Pressure (TM/LP) reactor trip. Prior to the reactor trip, the radioactivity is transported through the turbine to the condenser where the noncondensable radioactive materials would be released via the condenser air ejectors. As a result of the reactor trip, the turbine/generator trips and normal AC power may be lost. The electrical power would then be unavailable for the station auxiliaries such as the primary coolant pumps and the condensate pumps. Under such circumstances the plant would experience a loss of load, a loss of normal feedwater and forced primary coolant flow, a loss of condenser vacuum and steam generator blowdown.
The loss of offsite power subsequent to the time of reactor trip and turbine/generator trip is assumed in the analysis, since it produces the most adverse effect on the radiological releases. The plant is brought to shutdown cooling entry conditions by the operator per plant operating procedures. The time to reach shutdown cooling entry conditions will vary based on the availability of the following components; steam generator atmospheric dump valves (ADVs), available pressurizer heaters, auxiliary pressurizer spray, safety injection system and the auxiliary feedwater system.
Diagnosis of the SGTR accident is facilitated by secondary side radiation monitors which inform the operator of abnormal activity levels and that corrective operator action is required. These radiation monitors are located in the condenser air ejector discharge line, steam generator blowdown line, main steam lines, fan room, and in the stack. Additional diagnostic information is provided by PCS pressure and pressurizer level response indicating a leak as well as a decrease in the volume control tank level and the starting of the standby charging pumps.
The SGTR accident was evaluated by the NRC under Systematic Evaluation Program (SEP) Topic XV-17 (Reference 10). In this SEP evaluation, the NRC performed an independent analysis of a SGTR accident using assumptions and procedures indicated in the Standard Review Plan. The analysis assumes the plant is cooled down by releasing secondary steam to the environment through the main steam safety valves and the atmospheric
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-2 of 14.15-10 steam dump valves. On the basis of the NRC analysis, the NRC concluded that the Palisades plant design is acceptable with respect to the radiological consequences of a postulated steam generator tube rupture, and that the risk presented by this accident was similar to that of plants licensed under the more current criteria that existed at the time of the SEP. See Section 1.8.1 for additional discussion of the SEP.
The NRC issued Task Interface Agreement (TIA) 2009-003 (Reference 11) to address the reliance on the non-safety related atmospheric dump valves in the steam generator tube rupture analysis. The TIA concluded that the NRC approved the use of the non-safety related atmospheric dump valves as an acceptable method of mitigating a steam generator tube rupture in the original safety evaluation report for Palisades, and that this method is part of Palisades licensing basis.
14.15.2 THERMAL-HYDRAULIC ANALYSIS 14.15.2.1 Analysis Method The thermal-hydraulic response of the Nuclear Steam Supply System (NSSS) to the steam generator tube rupture with a loss of offsite power was simulated using the CESEC-III computer program for the first 30 minutes. At this time the operator is assumed to take control of the plant. Operator actions to mitigate the effects of the SGTR event and bring the plant to shutdown cooling entry conditions were simulated using a CESEC-III based cooldown algorithm. The CESEC-III computer program is described in Reference (1).
14.15.2.2 Bounding Event Input The initial conditions and input parameters employed in the analyses of the system response to a steam generator tube rupture with a concurrent loss of offsite power are listed in Table 14.15-1. Additional discussion on the input parameters and the initial conditions are provided below. Conditions were chosen to maximize the radiological releases.
A parametric study using CESEC was performed to determine the effect of reactor trip time on doses. The trip setpoint was raised to yield an earlier trip and compared to a SGTR analysis in which the reactor trip (low pressurizer pressure setpoint) was biased low. The result of this comparison showed that while the integrated tube leakage was higher for the delayed trip case at 1800 seconds, the early reactor trip case had higher doses at that time due to larger leakage during the times when the MSSVs were open. However, the integrated Exclusion Area Boundary (EAB) doses at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for both accident Generated Iodine Spike (GIS) and Pre-existing Iodine Spike (PIS) were larger for the delayed reactor trip case. This is due to decay heat being lower during the cooldown portion of the early reactor trip case. With a smaller PCS heat load, the PCS pressure is lower, which in turn reduces the tube leakage rate.
In addition, the PCS begins an earlier cooldown (via the MSSVs) so that primary and secondary temperatures and pressures are lower during the
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-3 of 14.15-10 transient than for the case of the delayed reactor trip. Therefore, the delayed trip assumption was selected for analysis based on this parametric study using the CESEC-based algorithm.
The initial conditions include the maximum allowed PCS pressure, nominal initial pressurizer liquid volume, maximum core power, minimum core coolant flow, and maximum core coolant inlet temperature. Table 14.15-2 contains assumptions regarding the system setpoints used in the analysis.
The operator actions, event recovery strategy and use of specific plant components assumed in this analysis were chosen to maximize the radiological releases while cooling the plant to shutdown cooling entry conditions following a SGTR event. The actual actions taken, recovery strategy and components used may be different from those assumed in the analysis, but will result in lower radiological releases than calculated in the bounding analysis. The major operator actions assumed in the analysis are summarized below. The timing of operator actions was based on Reference (3), which specifies time response criteria for safety related operator actions.
The first intervention by the operator was assumed at 30 minutes after event initiation. Subsequently, a time delay of two minutes between each discrete operator action was assumed.
- 1)
An automatic Auxiliary Feedwater Actuation Signal (AFAS) is generated if the level in the SG falls below 23.7% NR. However, Auxiliary Feedwater (AFW) flow to the SG will not commence for 120 seconds after the signal. AFW flow to both steam generators is established prior to the first operator action at 30 minutes. The AFW system is left in the automatic mode until the affected steam generator (SG) is isolated.
- 2)
At 30 minutes after event initiation, the operator opens the ADVs of both SGs to cooldown the PCS at a rate of 75 °F/hr or less. The affected SG may be isolated only after the hot leg temperature (Th) reaches 525 °F.
- 3)
The operator maintains the SG level between 30% and 70% NR in the unaffected generator. However, the AFW flow to the affected SG will be maintained until it is isolated. This assumption is conservative, since it worsens the affected SG overfilling problem, and will result in higher doses.
- 4)
The operator isolates the affected steam generator when the hot leg temperature is 525 °F or less. The initial cooldown of the PCS is aimed at preventing re-opening of the MSSVs on the affected steam generator.
- 5)
The operator initiates auxiliary spray flow in order to depressurize the PCS to the SG pressure, about 1000 psia, after the isolation of the affected steam generator. The operator uses the HPSI system,
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-4 of 14.15-10 available pressurizer heaters, and auxiliary pressurizer spray to control PCS inventory and subcooling.
- 6)
After isolating the affected generator, the operator cools the PCS at 75 °F/hr or less, using the unaffected steam generator. Note that a cooldown of less than 50 °F/hr is used in the analysis because it is a more realistic number for natural circulation conditions. The cooldown rate is reduced to a value which is designed to depressurize the PCS to shutdown cooling entry conditions in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This reduction in cooldown rate increases the radiological release during the long term cooldown by delaying entry into shutdown cooling until approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after event initiation, thereby maximizing the decay heat and the amount of radioactivity to be removed through the ADVs within the 0-8 hour time period.
- 7)
The operator attempts to maintain a subcooling margin of greater than 25 °F during the cooldown.
- 8)
The operator uses the ADV of the affected SG in order to keep the SG from overfilling. For this analysis, the radiological doses are conservatively high by keeping the affected SG level less than 90%.
14.15.2.3 Analysis of Results Table 14.15-3 presents a chronological sequence of events which occurs during the steam generator tube rupture event with a loss of offsite power from the time of event initiation (the double-ended rupture of a steam generator U-tube) to the attainment of shutdown cooling entry conditions (Reference 5). The sequence presented demonstrates that the operator can cool the plant down to shutdown cooling entry conditions during the event.
The dynamic behavior of important NSSS parameters following an SGTR is presented in Figure 14.15-1 to 14.15-21. Figures 14.15-1 through 14.15-10 depict event parameters from event initiation to 1800 seconds (30 minutes) when operator actions commence. Figures 14.15-11 through 14.15-21 are plant parameters through eight hours.
For a double-ended rupture, the primary to secondary leak rate exceeds the capacity of the charging pumps. As a result, the pressurizer pressure gradually decreases from an initial value of 2110 psia. At about 705 seconds, a reactor trip signal is generated when pressurizer pressure falls low enough to activate the TM/LP (low pressurizer pressure) trip. The reactor trip is followed by a turbine/generator trip. The loss of offsite power occurs 2 seconds after the turbine trip. Following the loss of offsite power, the primary coolant pumps coast down and natural circulation flow is established in the PCS.
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-5 of 14.15-10 Following the turbine trip, with turbine bypass unavailable, the main steam system pressure increases until the MSSVs open to release steam. A maximum main steam system pressure of approximately 1040 psia occurs around 725 seconds (Figure 14.15-4). Subsequent to this peak in the pressure, the main steam system pressure decreases, resulting in intermittent opening and closing of the MSSVs until 30 minutes into the event, at which point the operator intercedes by opening the ADVs to commence a cooldown.
From then on, the steam is released through ADVs only (Figure 14.15-18).
Prior to reactor trip, the main feedwater control system is assumed to be in the automatic mode supplying feedwater to the steam generators such that steam generator water levels are maintained. Following the reactor trip, the main feedwater flow is ramped down at 5%/second commencing approximately 6.5 seconds after the loss of offsite power. As the level in the steam generators decrease below 23.7% NR, an AFAS signal is generated approximately 24.5 minutes into the event. The AFW flow begins reaching the steam generators 2 minutes later at a rate of 200 gpm per generator. If the low level setpoint is reached in one generator (unaffected SG only), the AFW flow is assumed to go to both generators until the time at which operator action isolates the affected SG (50 minutes).
The pressurizer empties at 725 seconds (Figure 14.15-7) resulting in rapid decrease in the PCS pressure. Soon afterwards, the reactor vessel upper head region begins to void due to flashing caused by the continued PCS depressurization and the boil off of coolant caused by heat transfer from the upper head metal. Essentially, the upper head begins to act like a pressurizer. Consequently, the PCS pressure decreases at a slower rate (Figure 14-15-3).
At 716 seconds a safety injection actuation signal is generated, and by 811.5 seconds the safety injection flow begins to enter the PCS when the PCS pressure has decreased to below the shutdown head of the HPSI pumps. At 1800 seconds, the operator takes control of the plant. The first action is to open the ADVs to commence a cooldown. Twenty minutes later, the operator isolates the affected steam generator, securing feed and shutting the associated MSIV and ADVs. The operator adjusts the ADVs of the intact steam generator to cooldown the plant at a rate of 50 °F/hr or less. The AFW flow to the intact steam generator is adjusted to maintain levels between 30%
and 70% NR.
After isolation of the affected SG, the two steam generator pressures diverge (Figure 14.15-14). The isolated steam generator pressure increases due to flashing of the PCS fluid through the tube break. The intact steam generator pressure continues to decrease due to steaming via the ADV.
The operator initiates auxiliary pressurizer spray in order to depressurize the PCS (Figure 14.15-13) to within 50 psi of the affected SG pressure and thus reduce the leak flow (Figure 14.15-16).
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-6 of 14.15-10 The operator also controls the safety injection flow, auxiliary pressurizer spray flow and the available pressurizer heaters to maintain a minimum subcooling of 25 °F on the qualified Core Exit Thermocouples (CETs) and a pressurizer level of 20% to 90%.
At 13000 seconds, the affected steam generator level has increased to 90%
WR, and the operator opens the ADV to reduce the level. After this time, the operator periodically steams the affected steam generator to prevent it from overfilling. Steaming the affected SG is conservative in determining the radiological consequences.
After reaching shutdown cooling entry conditions and engaging the shutdown cooling system, it is assumed that no further steam release occurs from steam generators.
The maximum PCS and secondary pressures do not exceed 110% of design pressure following a steam generator tube rupture event with a loss of offsite power, thus, assuring the integrity of the PCS and the main steam system.
Figure 14.15-19 gives the integrated ADV releases from the affected and intact steam generators. At 1800 seconds when the operator takes control of the plant, 44,654 lbs of steam have escaped from the affected steam generator via the MSSVs. During the same time, 61123 lbs of primary liquid leaked into the affected steam generator. The integrated ADV steam releases and leak flow results for the 0-2 hour and 0-8 hr periods are shown in Table 14.15-4.
14.15.3 RADIOLOGICAL ANALYSIS 14.15.3.1 Analysis Method The analysis of the radiological consequences considers the most severe release of secondary as well as primary system activity leaked from the tube break. The analysis is consistent with the methodology described in Regulatory Guide 1.183, Appendix F, "Assumptions for Evaluating the Radiological Consequences of a PWR Steam Generator Tube Rupture Accident," (Reference 2). The inventory of fission product activity available for release to the environment is a function of the primary to secondary coolant leakage rate, the assumed increase in fission product concentration for Iodine GIS dose, and the mass of steam discharged to the environment.
The CESEC computer code was used to determine the mass and energy releases during the first 30 minutes of the event. As documented in Reference 8, an error was detected in the decay heat portion of the CESEC computer code, with the result being an underprediction of releases for the first 30 minutes. Also, an error in the assumed HPSI flow rate was discovered in the SGTR thermal hydraulic analysis (Reference 9). The SGTR offsite and Control Room doses were revised to correct for these errors (Reference 9). In addition, the SGTR Previous Iodine Spike (PIS) scenario
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-7 of 14.15-10 iodine release rates account for the Technical Specification limit of 40 Ci/gm.
Table 14.15-5 provides the significant input parameters for the dose calculations.
14.15.3.2 Bounding Event Input The assumptions and parameters employed for the evaluation of radiological releases are (Reference 7):
- 1)
Doses are calculated for two different assumptions: (a) an event generated iodine spike (GIS) coincident with the initiation of the event, and (b) a pre-accident iodine spike (PIS).
- 2)
A portion of the primary fluid that leaks into the faulted SG flashes into steam. The amount that flashes depends on the enthalpy of the primary liquid and the saturation enthalpy of the SG. The flashing portion has a decontamination factor calculated according to the methods described in Regulatory Guide 1.183, Appendix F (Reference 7). The non-flashing portion of the primary leak flow is assumed to mix uniformly with the liquid in the SG.
- 3)
Following the accident, no additional steam and radioactivity are released to the environment when the shutdown cooling system is placed in operation.
- 4)
The SG is assumed to have a decontamination factor of 100 in accordance with Regulatory Guide 1.183 (Reference 7), so that the radioactivity concentration in the steam phase is 1/100 of the concentration in the liquid phase.
- 5)
A primary-to-secondary leakage rate of 432 gallons per day is assumed in the unaffected steam generator for the duration of the transient to conservatively calculate the radiation released.
- 6)
Accident doses are calculated for two different assumptions, which are the Pre-existing Iodine Spike (PIS), and event Generated Iodine Spike (GIS). For the PIS conditions, the primary system activity is 40 Ci/
gm. For the GIS case, an initial activity of 1 Ci/gm and a spiking factor of 335 is assumed. See the discussion on calculation of PCS activity below.
- 7)
An initial secondary iodine activity of 0.1 Ci/gm is assumed (Technical Specifications Limit).
Table 14.15-5 lists the assumptions used in the radiological analysis.
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-8 of 14.15-10 14.15.3.3 Analysis of Results The initial PCS activity is assumed to be the equilibrium concentration prior to the accident.
Regulatory Guide 1.183 indicates that dose calculations for two types of iodine spiking cases be considered. This is due to iodine concentration increasing following a PCS pressure transient, such as a reactor trip. This phenomenon is known as iodine spiking. The two types of iodine spiking cases that must be considered are event generated iodine spike, GIS, and pre-accident iodine spike, PIS. The iodine spiking factor is defined as the ratio of the appearance rate of I-131 in the PCS following the event to the appearance rate required to produce a steady state equilibrium concentration.
The GIS iodine spike is a direct consequence of the PCS depressurization and shutdown caused by the SGTR event. A spiking factor of 335 is used in accordance with Regulatory Guide 1.183. The analysis conservatively assumes a step change in the iodine rate of appearance at the initiation of the SGTR which lasts eight hours to maximize the impact on the EAB doses.
The PCS initial radioactivity concentration was assumed to be the Technical Specification value of 1 Ci/gm for this analysis.
The PIS iodine spike is assumed to occur during a period of high PCS activity which was initiated by an independent event prior to the SGTR. The PCS activity remains high during the event and does not decrease further because of the event. An initial coolant activity of 40 Ci/gm was assumed for this analysis. A spiking factor of 1 was used in this part of the analysis.
For the GIS case, the initial PCS activity is the Technical Specification value of 1 Ci/gm. However, the primary activity increases steadily due to the large spiking factor. Since the large spiking factor is assumed to exist for a long period of time, the eight hour GIS case doses are higher than for the PIS case. The actual doses depend upon the timing of the radioactivity release to the atmosphere during the event.
The two-hour Exclusion Area Boundary (EAB) and the eight-hour Low Population Zone (LPZ) boundary doses for both the GIS and the PIS are presented in Table 14.1-6. For a postulated SGTR accident with an assumed PIS, the dose limits are 25 rem TEDE. For an assumed accident GIS, the dose limits are 2.5 rem TEDE. These limits apply to both the EAB and the LPZ. The dose acceptance criteria are derived from Regulatory Guide 1.183 and 10 CFR 50.67. The calculated EAB and LPZ doses are well within the acceptance criteria.
FSAR CHAPTER 14 - SAFETY ANALYSIS Revision 32 SECTION 14.15 Page 14.15-9 of 14.15-10 14.
15.4 CONCLUSION
S The radiological releases calculated for the SGTR event with a loss of offsite power are well below the limits for offsite doses. The doses to control room personnel are discussed in Section 14.24. Finally, the PCS and secondary system pressures during the SGTR remain below 110% of the design pressure limits, thus, assuring the integrity of these systems.
FSAR CHAPTER 14 - SAFETY ANALYSIS TABLE 14.15-3 Revision 21 Page 1 of 2 SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF OFFSITE POWER Time Setpoint (second)
Event or Value 1.0 Tube rupture occurs 32.9 Proportional heaters are fully energized, psia 2085 105.7 Backup heaters are energized, psia 2035 211.3 Heaters are de-energized on low level in the pressurizer, ft 3 558.6 703.7 Pressurizer pressure reaches low pressurizer pressure setpoint (TM/LP floor), psia 1700.
704.8 Trip signal is generated 705.2 Trip breakers open 706.1 Turbine Valves begin to close 707.1 Turbine valves are completely closed 708.2 Loss of offsite power 714.8 Feedwater flow begins ramping down at a rate of 5%/second 715.9 SIAS setpoint is reached, psia 1605 720.3 MSSVs begin to open, psia 1000 725.8 Pressurizer empties 733.9 Safety Injection pumps reach full speed 735.0 Upper head void begins to appear 811.5 Safety Injection flow to RCS begins, psia 1237.7 995.0 Maximum upper head void fraction 0.271 1107.0 Minimum PCS pressure, psia 1107.8 1370.5 Upper head void disappears
FSAR CHAPTER 14 - SAFETY ANALYSIS TABLE 14.15-3 Revision 21 Page 2 of 2 SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF OFFSITE POWER Time Setpoint (second)
Event or Value 1372.0 Pressurizer begins to refill 1466.6 Low steam generator level signal for Auxiliary feedwater actuation, ft 25.7 1586.6 Auxiliary feedwater reaches the steam generators, lbm/sec/SG 27.0 1800.0 Operator takes action, opens ADVs to initiate cooldown 3000.0 Operator isolates the affected SG, below setpoint loop temperatures, °F 525.0 13000.0 Operator initiates steaming the affected generator to avoid overfilling, percent SG wide range span 90 23300.0 Shutdown Cooling entry condition is reached, PCS pressure, psia/temperature, °F 270/300 28800.0 PCS pressure and temperature demonstrated to be stabilized, transient terminated.
FSAR CHAPTER 14 - SAFETY ANALYSIS TABLE 14.1-6 Revision 33 Page 1 of 4
SUMMARY
OF RADIOLOGICAL CONSEQUENCES OF THE CHAPTER 14 EVENTS FSAR SECTION SCENARIO DESCRIPTION OFFSITE DOSES AND LIMITS CONTROL ROOM HABITABILITY Section 14.11:
CASK DROP IN THE SPENT FUEL POOL (Section 14.24 for CRH)
Cask Drop Scenario Pre-Isolation
% Filter Bypass Post-Isolation
% Filter Bypass Offsite Dose Limits (5)
[rem]
Exclusion Area Boundary (0-2 hrs)
[rem]
Low Population Zone
[rem]
Time to E-HVAC
[min]
Control Room Dose Limits (6)
[rem]
Control Room Dose
[rem]
CRE Inleakage
[cfm]
30 Day Decay w/Charcoal Filters N/A 10 TEDE 6.3 2.04 0.25 0 min TEDE 5
1.37 100 cfm 30 Day Decay w/Charcoal Filters N/A 17.5 TEDE 6.3 2.78 0.35 0 min TEDE 5
1.99 100 cfm 90 Day Decay No Charcoal Filters 100 100 TEDE 6.3 0.08 0.01 Not Required (3)
TEDE 5
1.67 100 cfm Section 14.14:
STEAM LINE BREAK (Section 14.24 for CRH)
Dose Calculation Assumptions Offsite Dose Limits (5)
[rem]
Exclusion Area Boundary (0-2 hrs)
[rem]
Low Population Zone
[rem]
Time to E-HVAC
[min]
Control Room Dose Limits (6)
[rem]
Control Room Dose
[rem]
CRE Inleakage
[cfm]
Break Outside the Containment TEDE 25 0.67 0.20 20 min TEDE 5
3.34 20 cfm Section 14.15:
STEAM GENERATOR TUBE RUPTURE WITH A LOSS OF OFFSITE POWER (Section 14.24 for CRH)
Iodine Spike Assumptions Offsite Dose Limits (5)
[rem]
Exclusion Area Boundary (0-2 hrs)
[rem]
Low Population Zone
[rem]
Time to E-HVAC
[min]
Control Room Dose Limits (6)
[rem]
Control Room Dose
[rem]
CRE Inleakage
[cfm]
Previous Iodine Spike TEDE 25 0.99 0.22 20 min TEDE 5
3.79 100 cfm Generated Iodine Spike TEDE 2.5 1.17 0.21 20 min TEDE 5
3.48 100 cfm Section 14.16:
CONTROL ROD EJECTION EVENT (Section 14.24 for CRH)
Dose Calculation Assumptions Offsite Dose Limits (5)
[rem]
Exclusion Area Boundary (0-2 hrs)
[rem]
Low Population Zone
[rem]
Time to E-HVAC
[min]
Control Room Dose Limits (6)
[rem]
Control Room Dose
[rem]
CRE Inleakage
[cfm]
Containment Release TEDE 6.3 2.60 0.68 Auto Switch (4)
TEDE 5
1.27 20 cfm Steam Generator/ADV Release TEDE 6.3 2.70 0.43 20 min TEDE 5
1.00 20 cfm
License Amendment Request to Revise the Palisades Nuclear Plant Site Emergency Plan to Support Resumption of Power Operations ML24122C666
PALISADES POWER PLANT EAL Basis EMERGENCY IMPLEMENTING PROCEDURE Revision 9 Page 280 Fission Product Barrier Loss/Potential Loss Matrix and Basis TITLE: EMERGENCY ACTION LEVEL TECHNICAL BASES Barrier:
Primary Coolant System Category:
B. Inventory Degradation Threat: Loss Threshold:
Implementing Guidance None Generic This threshold addresses the full spectrum of Steam Generator (SG) tube rupture events in conjunction with containment barrier loss thresholds. It addresses RUPTURED SG(s) for which the leakage is large enough to cause actuation of ECCS (SIAS). This is consistent to the PCS leak rate barrier potential loss threshold.
By itself, this threshold will result in the declaration of an Alert. However, if the SG is also FAULTED (ie, two barriers failed), the declaration escalates to a Site Area Emergency per Containment barrier loss thresholds.
There is no potential loss threshold associated with this item.
Plant-Specific By definition of the term "RUPTURED," the size of the primary-to-secondary leakage considered in this PCS Loss threshold must be sufficient to require or cause a reactor trip and safety injection. ECCS (SIAS) actuation in conjunction with the RUPTURED SG, therefore, emphasizes the magnitude of the rupture threatening this fission product barrier.
PLP Basis Reference(s):
- 1. EOP-5.0, "Steam Generator Tube Rupture Recovery"
PALISADES POWER PLANT EAL Basis EMERGENCY IMPLEMENTING PROCEDURE Revision 9 Page 72 Emergency Action Level Bases TITLE: EMERGENCY ACTION LEVEL TECHNICAL BASES Category:
A - Abnormal Rad Release / Rad Effluent Subcategory:
1 - Offsite Rad Conditions Initiating Condition: Offsite dose resulting from an actual or IMMINENT release of gaseous radioactivity greater than 1000 mRem TEDE or 5000 mRem thyroid CDE for the actual or projected duration of the release using actual meteorology EAL:
AG1.3 General Emergency Field survey results indicate closed window dose rates > 1,000 mRem/hr expected to continue for t 60 min. at or beyond the SITE BOUNDARY OR Analyses of field survey samples indicate thyroid CDE > 5,000 mRem for 1 hr of inhalation at or beyond the SITE BOUNDARY (Note 1)
Note 1:
The ED should not wait until the applicable time has elapsed, but should declare the event as soon as it is determined that the condition will likely exceed the applicable time Mode Applicability:
All Basis:
Implementing Guidance None Generic This EAL addresses radioactivity releases that result in doses at or beyond the SITE BOUNDARY that exceed the EPA Protective Action Guides (PAGs). Public protective actions will be necessary.
Releases of this magnitude are associated with the failure of plant systems needed for the protection of the public and likely involve fuel damage.
Since dose assessment is based on actual meteorology, whereas the monitor reading EAL is not, the results from these assessments may indicate that the classification is not warranted, or may indicate that a higher classification is warranted. For this reason, emergency implementing procedures should call for the timely performance of dose assessments using actual meteorology and release information. If the results of these dose assessments are available when the classification is made (eg, initiated at a lower classification level), the dose assessment results override the monitor reading EAL.
Plant-Specific