Entergy's Got a Busy Southern Fleet Of Regulated Plants

Entergy got rid of their merchant fleet of nuclear Plants, it didn't fix their nuclear plant problems.

Power Reactor	Event Number: 54096
Facility: RIVER BEND Region: 4     State: LA Unit: [1] [] [] RX Type: [1] GE-6 NRC Notified By: ALFONSO CROEZE HQ OPS Officer: JEFFREY WHITED	Notification Date: 06/01/2019 Notification Time: 03:15 [ET] Event Date: 05/31/2019 Event Time: 23:45 [CDT] Last Update Date: 06/01/2019
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL	Person (Organization): JASON KOZAL (R4DO)

Unit

SCRAM Code

RX Crit

Initial PWR

Initial RX Mode

Current PWR

Current RX Mode

1

M/R

Y

30

Power Operation

0

Hot Shutdown

Event Text

MANUAL REACTOR SCRAM DUE TO LOW REACTOR WATER LEVEL "At 2345 CDT at River Bend Station (RBS) Unit 1, a manual Reactor scram was inserted in anticipation of receiving an automatic Reactor Water Level 3 (9.7") scram due to the isolation of the 'B' Heater String with the 'A' Heater String already isolated. The 'B' heater string isolation caused loss of suction and subsequent trip of the running Feed Water Pumps 'A' and 'C'. All control rods fully inserted with no issues. Subsequently Reactor level was controlled by the Reactor Core Isolation Cooling (RCIC) system. Feed Water Pump 'C' was restored 4 minutes after the initial trip and the RCIC system secured. Currently RBS-1 is stable and is being cooled down using Turbine Bypass Valves. "No radiological releases have occurred due to this event from the unit." The plant is currently under a normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector.

ANO Tripped...Lots Of Unreliablity In Their Fleet

Power Reactor	Event Number: 54091
Facility: ARKANSAS NUCLEAR Region: 4     State: AR Unit: [] [2] [] RX Type: [1] B&W-L-LP,[2] CE NRC Notified By: MICHAEL STROBEL HQ OPS Officer: DAN LIVERMORE	Notification Date: 05/26/2019 Notification Time: 09:25 [ET] Event Date: 05/26/2019 Event Time: 05:12 [CDT] Last Update Date: 05/26/2019
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL 50.72(b)(3)(iv)(A) - VALID SPECIF SYS ACTUATION	Person (Organization): HEATHER GEPFORD (R4DO)

Unit

SCRAM Code

RX Crit

Initial PWR

Initial RX Mode

Current PWR

Current RX Mode

2

A/R

Y

100

Power Operation

0

Hot Standby

Event Text

AUTOMATIC REACTOR TRIP DUE TO A REACTOR COOLANT PUMP TRIP ON GROUND FAULT "This is a 4-hour Non-Emergency 10 CFR 50.72(b)(2)(iv)(B) notification due to a Plant Protection System (PPS) actuation. Arkansas Nuclear One, Unit 2, automatically tripped from 100 percent power at 0512 CDT. The reactor automatically tripped due to 2P-32B Reactor Coolant Pump tripping as a result of grounding. "No additional equipment issues were noted. All control rods fully inserted. Emergency Feedwater (EFW) actuated and was utilized to maintain Steam Generator (SG) levels. The EFW actuation meets the 8-hour Non-Emergency Immediate Notification Criteria of 10 CFR 50.72(b)(3)(iv)(A). No Primary safety valves lifted. Main Steam Safety Valves (MSSVs) did lift initially after the trip. "The NRC Resident Inspector has been notified. "Decay heat is being removed via the steam dump valves to the main condenser. Unit 2 is in a normal shutdown electrical lineup. Unit 1 was not affected by the transient on Unit 2. The licensee notified the State of Arkansas."

Should We Worrying About The Historic Flooding On The lower Mississippi With The Nukes

I have been watching the NRC's daily event reports carefully.

Grand Gulf, Waterford and River Bend

Morganza Spillway

Brunswick Nuclear Plant Operating While Drunk

Update

Welcome to you new NRC of deregulation, we should have had at least a special inspection. This is how they can game risk perspectives by pick and choosing what is put into the risk perspectives. And the NRC doesn't have to disclose why a special is not done... 

*They ought to get a red violation finding for allowing the reactor water instrument line to rupture uncontrollably. The leaking water into the drywell is not that important...it is the lost of the indication of the reactor water level along with the inaccurate activation and the missing activation with a host of critical systems designed to prevent a core meltdown. I get it, we got redundant systems. The example is, what if we had lost the other side's instrumentation coupling at the same time. What if a plant lost all reactor water indications. Even if we didn't have a meltdown, this accident would have dire problems for the industry. I bet this plant would have to do a emergency blowdown and fill up the drywell with water to get cooling water to the reactor. It would be a brutal accident that never had any testing on the emergency procedures. This would be in the news for a years.         

*My issues with this is that the reactor water level instrument line could have sheared off during a very complicated accident leading to meltdown. 

Here is your new world boys with unprecedented NRC deregulation. They don't have to publicly notify the community with serious accidents.  

***Here is the industry's crooked advocator trying to reduce the drunken driving charges with the plant operator.

Indications of a plant in serious troubles: 

PLANT STATUS
 Unit 1 began the inspection period at 100 percent rated thermal power (RTP) and operated there until February 22, 2019, when power was reduced to 60 percent RTP to perform a control rod sequence exchange, feed pump maintenance, scram time testing, and turbine valve testing.  The unit was restored to 100 percent RTP on February 23, 2019, where it continued to operate until February 24, 2019, when power was reduced to 85 percent RTP for a control rod improvement.  The unit was restored to 100 percent RTP on February 25, until March 10, 2019, when power was reduced to 82 percent RTP as a result of a recirculation pump runback caused by a loss of the Unit 1 uninterruptible power supply (UPS) bus.  Power was restored to 100 percent on the same day following restoration of the UPS bus and the unit continued to operate at 100 percent RTP until March 28 2019, when the unit was taken offline for a reactor coolant system leak in the 'B' train reference leg.  The unit remained offline and in mode 4 for the remainder of the inspection period.
 Unit 2 began the inspection period at 60 percent RTP as a result of a trip of the ‘A’ reactor feed pump (RFP) on December 31, 2018.  Following repairs to the ‘A’ RFP, the unit was returned to 100 percent RTP January 9, 2019.  Between January 9 and February 8, 2019, the unit operated between 95 percent and 100 percent RTP due to power to flow limitations.  Following several rod improvements during this period, the unit reached 100 percent on February 8 2019, and continued to operate there until February 25 when a power coast down was commenced.  On March 2, 2019, with the unit at 97 percent RTP, Unit 2 was shut down for a refueling outage and remained shut down until March 29, 2019, when the unit entered mode 2 and the reactor was taken critical.  On March 30 2019, with the turbine generator still disconnected from the grid and the reactor at approximately 20 percent RTP (mode 1), the reactor was manually tripped due high bearing vibrations (No. 9 bearing).  The operators subsequently placed the unit in mode 4 on March 31 2019, in order to effect repairs to the No. 9 main turbine bearing.

It is a white finding so far...  It is a leak performance that went to white. 

NEI 99-02 FAQ 19-02 Brunswick RCS Leakage 

 Page 1 of 10 Revised 20180520
Plant:   Brunswick Nuclear Power Plant Unit 1 Date of Event:   March 28, 2019 Submittal Date:   May 22, 2019 Licensee Contact:  Tony Zimmerman    Licensee Tel/email:  980-373-2520/Tony.Zimmerman@Duke-Energy.com NRC Contact:   Galen Smith, Brunswick NRC Senior Resident Inspector  Tel/email: (910) 832-2831, Galen.Smith@nrc.gov

Performance Indicator:  BI02 -  Reactor Coolant System Leakage 

Site-Specific FAQ (see Appendix D)? (X)Yes or (   ) No

FAQ requested to become effective (X) when approved or (other date) ____________


Question Section  

 Nuclear Energy Institute (NEI) 99-02 Guidance needing interpretation (include page and line citation): 
 NEI 99-02, Revision 7, Page 42, lines 3 – 6.  NEI 99-02 defines the purpose of the performance indicator for Reactor Coolant System (RCS) Leakage as:

3 This indicator monitors the integrity of the RCS pressure boundary, the second of the three 4 barriers to prevent the release of fission products. It measures RCS Identified Leakage as a 5 percentage of the technical specification allowable Identified Leakage to provide an indication of 6 RCS integrity. 

 Event or circumstances requiring guidance interpretation:  

 This FAQ is being submitted to request an exemption from the NEI 99-02 guidance to report elevated Reactor Coolant System (RCS) Leakage due to plant-specific circumstances or unique conditions.  Specifically, Brunswick Unit 1 is requesting an exemption related to the March 2019 RCS Leakage Performance Indicator (PI) data, which crossed the Green/White threshold due to the unique circumstances surrounding failure of a 1-inch instrument line coupling that occurred on March 28, 2019.  Brunswick does not have a Technical Specification limit on Identified Leakage and reports RCS Total Leakage for this PI, as discussed on NEI 99-02, page 42, lines 33 and 34.  The following describes the basis for this exemption request. 

 
 1. The RCS Leakage Performance Indicator is intended to monitor RCS leakage below the Technical Specification limit to ensure that licensees identify and trend leakage early and take timely corrective actions well before the technical specification limit is reached.  RCS pressure boundary material is ductile by design and typically exhibits a leak-beforebreak failure mechanism in which cracks begin small and leakage progresses over time.  The RCS Leakage Performance Indicator is intended to monitor licensee behaviors in taking prompt action to address RCS leakage before it reaches the limit in the Technical  

NEI 99-02 FAQ 19-02 Brunswick RCS Leakage

 Page 2 of 10 Revised 20180520
Specifications.

Contrary to this, the March 28, 2019, Brunswick event resulted from the immediate circumferential separation of a 1-inch coupling on the steam side sensing line for reactor vessel level indication, as shown in Figures 1 and 2.  Based on the material of construction and environmental conditions (i.e., temperature, hydrogen), the post-event metallurgical report determined the coupling showed no evidence of localized plastic deformation.  The coupling experienced hydrogen embrittlement and did not exhibit a leak-before-break failure mechanism.  There were no precursors to this event and the resulting leakage from the break exceeded the Technical Specification (TS) limit.  RCS leakage was stable and well below the TS limit before the event.  The steam leak could not be isolated from the reactor vessel.  Operations took prompt action to reduce power, commence a plant shutdown, and depressurized the reactor to stop the leak.  The leakage resulted in the declaration of an Unusual Event (UE).  Operations completed an uncomplicated reactor shutdown.  It was the last reading taken before entering Mode 4 (i.e., the Mode in which the SR is no longer applicable) that caused the PI to transition from Green to White.  RCS leakage was stable and was being appropriately managed before the event.  Based on these unique circumstances, Brunswick requests an exemption to exclude reporting the leakage from the event in the RCS Leakage PI.  This would result in the PI returning to Green for March 2019.  

    
 2. As a result of the event, the NRC initiated their event follow-up process (IMC 0309, “Reactive Inspection Decision Basis for Reactors”, and IP 71153, “Follow-Up on Events and Notices of Enforcement Discretion”) to determine if it was appropriate to enter Management Directive 8.3, “Incident Investigation Program” to initiate a follow-up inspection (Special Inspection).  In performing the “plant response and event follow-up checklist” the NRC evaluates control room conduct, the circumstances of the leak, plant conditions, and the associated risk of the event.  NRC determined that a Special Inspection was not needed.  Since the RCS leakage was low prior to the event with no precursors, the supplemental inspection initiated for a White PI would be redundant, in part, to that which has already been inspected.  Based on the fact that Brunswick has already replaced all the susceptible couplings in both Units and given the unique characteristics of this failure, plant-specific circumstances should be considered to exempt recording the leakage from the event as part of the indicator and evaluate under other NRC processes.  

 Problem Statement:  The RCS leakage Performance Indicator (PI) monitors leakage that is below the Technical Specification (TS) limit to ensure licensee’s take prompt actions to monitor, diagnose, mitigate, and correct RCS leakage to prevent it from progressing into a more significant condition.  

At Brunswick Nuclear Plant, Unit 1, RCS leakage was stable, monitored and managed well below the TS Limit with the PI low in the Green performance band prior to this event.  On March 28, 2019, a 1-inch instrument line failed without any prior indications, resulting in exceeding the TS limit for RCS total leakage, as shown in Figure 3.  A deliberate, controlled shutdown of Unit 1 was undertaken that was commensurate with the risk associated with the  

NEI 99-02 FAQ 19-02 Brunswick RCS Leakage

 Page 3 of 10 Revised 20180520 

leakage.  The location of the leak prevented it from being isolated, requiring the depressurization of the RCS to stop the steam leak.  There were no precursors for the failure of this instrument line.  The last data point taken in Mode 3 was 13.93 gpm as shown in Figure 4.  This was the only data point in March 2019 that exceeded the 50% of the TS Total Leakage Green/White threshold of >12.5 gpm.

NRC Region II implemented their event follow-up procedure and did not raise any concerns with the performance of the Operations crew responding to the leak.  Duke Energy’s position is that the absence of any precursor to the leakage and the prompt action of the Operations crew in responding to the leak provides special circumstances not addressed in the PI guidance.  Duke Energy requests an exemption to exclude reporting leakage from the event in the RCS leakage PI calculation, which would return the indicator to Green for March 2019. While this FAQ is being resolved, the Brunswick Unit 1 first quarter 2019 RCS Leakage PI was reported as White on April 22, 2019, for the PI exceedance on March 28, 2019.  

Brunswick, Unit 2 was shut down for a refueling outage during this event. 

 Event Description:  

 At 1419 on March 28, 2019, while operating at 100% reactor power, the Brunswick Nuclear Plant Unit 1 N004B narrow range reactor water level instrument (1-C32-LI-R606B) failed high.  N004B is an instrument tap off the steam space of the reactor vessel.  Drywell pressure and drywell floor drain leakage increased.  Operators controlled drywell pressure and reduced reactor power per the immediate power reduction instructions.  An Unusual Event was declared at 1450 based on elevated drywell leakage and reported to the NRC via Event Notification 53961.  A controlled shutdown of Unit 1 was undertaken that was commensurate with the risk associated with the leakage. This timely action by the operators mitigated the leakage while preventing an unnecessary transient on the plant by performing a scram from a high power level.   Timeline of event:
  March 28, 2019 – Unit 1 operating at full power  1419 – N004B narrow range Reactor Pressure Vessel level instrument failed high  Drywell pressure and floor drain leakage increased  Entered TS 3.4.4 RCS Leakage for unidentified floor drain leakage  Operators reduced reactor power per the immediate power reduction instructions  1429 – Drywell pressure slowly lowering in response to operator action  1438 – Drywell Floor Drain sump alarm increased above setpoint, automatic actions in progress (sump pump started)  1440 – Drywell Floor Drain sump level lowered below reset point and alarm cleared  1450 – Declared Unusual Event due to elevated drywell leakage  Operators continued reducing power in accordance with procedures  1600 – RCS leakage data recorded at 8.3 gpm as shown on Fig. 4  1603 – Operators completed a manual reactor shutdown in accordance with procedures  Reactor Pressure Vessel level maintained in established level band 
NEI 99-02 FAQ 19-02 Brunswick RCS Leakage

 Page 4 of 10 Revised 201805 

 Scram recovery and cooldown – no significant problems  2000 - RCS leakage data recorded at 11.51 gpm as shown on Fig. 4  March 29, 2019 – Unit 1 shutdown  0000 - RCS leakage data recorded at 13.93 gpm as shown on Fig. 4  0238 – Entered Mode 4 
 Investigation inside containment determined that a 1-inch coupling on line 1-B21-774 located on the steam side of a reactor level condensing chamber experienced a 360° circumferential separation at the approximate center of the coupling as shown in Figures 1 and 2 below.  This opened a path for steam from the reactor to leak into the drywell.  Reactor water level was maintained in the established level band, below the level of the sensing line nozzle, throughout the event. The impact from the coupling failure has been analyzed by the Duke Probabilistic Risk Assessment staff and determined to be very low safety significance.

Approximately 1.5 days before the event, the Brunswick, Unit-1 measured an increase in drywell pumping and implementing procedure 0OI-02.3, Drywell Leakage Control.  Investigations determined that the cause of the higher measured leakage was a failed vacuum breaker which allowed water to flow back into the sump after it had been pumped out, causing it to be counted twice by the integrator for the RCS Leakage calculation.  The integrator was observed to be ‘clicking’ or counting leakage when the pump was not running.  This measured leakage was not related to the coupling failure and did not represent an increase in actual RCS leakage.  In addition, there was no indication of increased activity on any of the Radiation Monitors, which provides additional assurance that this was unrelated to the coupling failure.  The vacuum breaker was repaired during the outage and leakage rates returned to historical normal values.  
 Basis for Exemption from guidance:  

 Appendix E of NEI 99-02, Revision 7, allows an exemption to be submitted via the FAQ process for plant-specific circumstances such as unique conditions. Duke Energy is requesting this based on the unique conditions of this RCS leak in that it was not a leak-before-break and not indicative of chronic unresolved elevated RCS leakage.  The RCS Leakage Performance Indicator is intended to monitor how licensees manage RCS leakage below the TS limit to ensure that timely corrective actions are taken in advance of reaching the TS limit.  As stated in Appendix C of SECY 1999-007, Barrier Integrity Key Attributes and Means to Measure: Research has determined the RCS pressure boundary has a high probability of experiencing a leak prior to a rupture (i.e. "leak-before-break"). Therefore, the extent of such leaks offers an objective perspective on the probability of a more catastrophic failure.  

A foundational assumption of this Performance Indicator is that the RCS pressure boundary has a high probability of “leak-before-break” and that the PI is intended to monitor these precursor events.  Additionally, in NRC Staff White Paper titled, Objective of the RCS Leakage Performance Indicator, from the June 26, 2013, ROP Working Group Public Meeting (ML13203A258), the NRC Staff made the following statement on page 20 of 60 regarding an Observation from the Davis-Besse Lessons Learned Task Force (LLTF): 

NEI 99-02 FAQ 19-02 Brunswick RCS Leakage

 Page 5 of 10 Revised 20180520  

As documented in LLTF recommendation 3.3.3(3), the intent of the current RCS Leakage PI is to call attention to those plants that have identified primary systems leaks but have not corrected them in a timely manner.

The PI is intended to monitor leak-before-break situations that are viewed as precursors of a more catastrophic failure.  In the Brunswick event, RCS Total leakage had been steady for the month of March as shown below in Figure 3.   There was no advanced indications of degradation or leakage from the coupling and no trend that worsened over time due to operator inaction. 

As shown in Figure 3, RCS Leakage trends were stable and low in the Green performance band for the month leading up to the coupling failure.  The coupling failure occurred without warning.  Drywell leakage and temperature in the vicinity of the coupling did not increase prior to the failure.  There was no opportunity for Operations staff to identify this condition in advance of failure.  As no precursors were present, no mitigating actions could have been taken in advance of the leak and the actions taken following the leak indicate prompt and conservative response on the part of the licensee.  In addition, the location of the leak prevented it from being isolated until the plant was depressurized, which added to the volume of the leakage calculated in the PI.  Despite timely operator actions to accomplish this, the volume of leakage calculated in the PI resulted in one calculation data point exceeding the threshold for White.  The degradation mechanism of the coupling will be evaluated under other NRC processes.  

The leakage measured during the event should not be counted in the RCS Leakage PI because the operators exhibited the behaviors consistent with the intent of the performance indicator.  Operations took prompt action to conduct a safe and stable shutdown, minimizing the transient to the plant, in the interest of safety.  Including this leakage in the performance indicator and taking the actions associated with a White PI could have the unintended consequence of providing an incentive to licensees to depressurize the plant in a less controlled manner without a commensurate benefit to public health and safety.

A Root Cause Evaluation was initiated following the March 28, 2019.  The coupling that failed was a 1” Cryofit (cryogenic) coupling.   Cryofit couplings are devices used to connect small bore piping (1-inch nominal pipe size and less) without welding.  They are fabricated from a shape memory alloy (SMA) material composed primarily of Nickel-Titanium-Iron (Tinel) which experiences a phase change at cryogenic (extremely low) temperatures.  To prepare for installation, the Cryofit coupling is cooled below the transformation temperature.  The ends of the coupling are then expanded and the coupling is stored in the cold, expanded state.  The pipe ends are inserted into the coupling while it is cold.  The phase change causes the coupling to shrink as its temperature rises from its installation temperature of less than -200° F to ambient temperature and above.  This results in an interference fit that does not require welding.  This unique effect is produced by a phase transformation, i.e., an instantaneous shear transformation between the alloy’s body-centered cubic austenite phase and its highly twinned martensite phase.  These couplings had been installed at Brunswick for approximately 30 years.

Examination of the failed coupling was conducted at the McGuire Island Metallurgical lab.  Microhardness testing, visual microscopy and scanning electron microscopy were used to characterize the failed material.  Using metallurgical analysis and investigation of the process  

NEI 99-02 FAQ 19-02 Brunswick RCS Leakage

 Page 6 of 10 Revised 20180520  

conditions at the coupling location, the Root Cause Evaluation team determined that the failure was due to hydrogen embrittlement of the Tinel material.  This resulted from many years of exposure to high temperature and high levels of hydrogen.  This conclusion is supported by the transgranular cleavage, high hardness values in the region exposed to the process fluid, and a hydrogen rich environment, which are all consistent with hydrogen embrittlement.

An evaluation was performed to address the couplings installed in both units.  All couplings exposed to reactor steam (i.e., potentially susceptible) were removed and replaced with welded fittings prior to startup of Units 1 and 2.   In addition, the installation procedure for the couplings was placed on hold pending revision, to prevent any further installation of Cryofit couplings.  

RCS Leakage Data Collection:

The BNP Technical Specifications defines the frequency of Surveillance Requirement (SR) 3.4.4.1, RCS Operational Leakage, in accordance with the Surveillance Frequency Control Program (SFCP).   The Brunswick SFCP has an 8-hour frequency for this SR.   This is consistent with NUREG-1433, Revision 4, General Electric BWR/4 Standard Technical Specifications, which lists an RCS Operational Leakage Surveillance Requirement frequency of 8 hours, or in accordance with the SFCP.  As a normal practice, Brunswick performs this surveillance every 4 hours in Modes 1 through 3 as a conservative approach to ensure the completeness of the required surveillance.  It was the last data point collected before entering Mode 4 that caused the PI to transition from Green to White.      

Nation Wide Nuclear Industry Disgrace

https://adamswebsearch2.nrc.gov/webSearch2/main.jsp?AccessionNumber=ML14184B061

BRAIDWOOD STATION, UNITS 1 and 2, and BYRON STATION, UNITS 1 and 2 - IMPOSITION OF FACILITY-SPECIFIC BACKFIT RE:  COMPLIANCE WITH LICENSING BASIS PLANT DESIGN REQUIREMENTS (TAC NO. MF3206) 

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257
March 21, 2016
MEMORANDUM TO: Marissa G. Bailey, Acting Director Division of Engineering Office of Nuclear Reactor Regulation
FROM:
SUBJECT: INPUT FOR EXELON BACKFIT REVIEW PANEL
In a memorandum to you dated January 12, 2016, William M. Dean tasked us to provide a recommendation on whether a backfit is necessary at Byron and Braidwood and whether the application of the compliance backfit was appropriate and in accordance with 10 CFR 50.109(a)(4)(i). The Exelon Generation Company’s, LLC (EGC) appeal to the U.S. Nuclear Regulatory Commission (NRC) was dated December 8, 2015. The NRC backfit was imposed in a letter dated October 9, 2015, which stated that the Byron and Braidwood Stations were not in compliance with General Design Criteria (GDC) 15, GDC 21, GDC 29, 10 CFR 50.34(b), and the plant-specific design bases. The backlit documents two primary issues with the licensee’s analyses: (1) failure to evaluate a stuck open Power Operated Relief Valve (PORV), and (2) failure to properly qualify the Pressurizer Safety Valve (PSV) for water relief.
After reviewing the assessment provided by Mr. Gendelman, Office of General Counsel, I concur that the staff implemented the backfit appropriately in accordance with 10 CFR 50.109(a)(4)(i) and NRC Management Directive 8.4. However, my assessment is that the backfit was not implemented appropriately in accordance with NRR Office Instruction LIC-202, Revision 2. Specifically, I suggest that the use of a plant-specific backfit may not be the most appropriate method for addressing the generic nature of the technical issues associated with this event. NRR 01 LIC-202, Section 1 states, ‘a backfit is plant-specific when it involves the imposition of a position that is unique to a particular plant,” in the case of Byron and Braidwood, I believe the issues communicated in the backfit are not unique to these plants.
Following the Three Mile Island accident, the NRC ordered licensees to implement numerous changes to their facilities and operating procedures. Some of these changes were focused on improving the PORV and block valve reliability, supplying Class 1 E power to the PORV and block valve, and to have position indication in the control room. NUREG-1316, “Technical Findings and Regulatory Analysis Related to Generic Issue 70,” concluded that it was not cost effective to upgrade (backfit) existing non-safety-grade PORVs and block valves (and associated control systems) to full safety-grade qualification status when they have been determined to perform any of the safety-related functions discussed in the NUREG or any identified in the future.
CONTACT: Anthony I. Gody, DRS 404 997-4600
M. Bailey 2
In Regulatory Issue Summary 2005-29, Revision 1, the staff reiterated the NRC position that Condition II events are not allowed to progress to Condition Ill or IV events and indicated that PSVs and PORVs (and associated block valves) are not safety-related or qualified for water relief.
Arguably, if these components are relied upon to satisfy a Chapter 15 accident analysis, they are required to be both safety-related and qualified to accomplish the intended safety function (See 10 CER, Part 50, Appendix A, General Design Criteria 1 and 10 CFR, Part 50, Appendix B). In 1993 and 1994, Westinghouse addressed a Nuclear Safety Advisory Letter (NSAL-93013 and NSAL-93-013 Supplement 1)to many pressurized water reactor licensees. In these NSALs, Westinghouse advised licensees that their pressurizer could fill much faster than anticipated during an increase in reactor coolant inventory event and recommended that they employ a strategy that used PORVs and associated block valves in their procedures.
I reviewed 10 UFSARs and developed a brief summary of the various strategies used by licensees in addressing the increased reactor coolant inventory event. The quick review identified a wide range of strategies that were accepted by the NRC. The review identified some interesting facts as follows: two licensees rely solely on the PSVs being capable of opening and reseating due to water temperature above 500 degrees F (no supporting analyses is referenced for this conclusion), four licensees rely on a PORV and its block valve in their strategy but do not appear to address whether PORV/block valve are safety-related and qualified to operate in water blowdown conditions, two licensees directly reference the same Electric Power Research Institute (EPRI) test reports that Byron and Braidwood referenced as part of their mitigation strategy. Furthermore, licensees have implemented procedures to address high pressurizer level or inadvertent actuation of emergency core cooling (ECCS) events that employ the following strategy: assess the event, determining whether the ECCS actuation is appropriate, secure excess injection, re-establishing containment air and letdown, and control either pressurizer level with charging/letdown or reactor pressure with PORVs if solid. At least one licensee successfully avoided having to address the technical issues of the PSV and PORV passing water altogether with the statement that they can terminate a reactor coolant system overfill event before the pressurizer fills solid. One extreme example of this strategy approved by the NRC indicated that emergency core cooling system would be terminated as fast as 14 minutes. Most licensees rely on the PORV and block valve cycling (I think in automatic), preventing the reactor coolant system pressure rising above the PSV set point, while operators assess and terminate the overfill situation. One licensee documents that the PORV would cycle 88 times before injection could be stopped, it appears the PORV is in automatic during this operation.
In conclusion, the staff imposition of a plant-specific backfit to Byron and Braidwood was in accordance with 10 CFR 50.109(a)(4)(i) and NRC Management Directive 8.4. However, my assessment is that the backfit was not implemented appropriately in accordance with NRR Office Instruction LIC-202, Revision 2. Specifically, I suggest that the use of a plant-specific backfit may not be the most appropriate method for addressing the generic nature of the technical issues associated with this event. NRR 01 LIC-202, Section 1 states, “a backfit is plant-specific when it involves the imposition of a position that is unique to a particular plant,” in the case of Byron and Braidwood, I believe the issues communicated in the backfit are not unique to a particular plant. My recommendation is that the staff consider implementing the NRC MD 6.4 process to revisit GSI-70, decide if the issues identified in the Byron and Braidwood backfit are indeed generic, and, if so, initiate actions to issue a generic backfit for this issue and begin an interaction with the nuclear industry using the NRC Principles of Good Regulation.
M. Bailey 3
The transparent use of risk insights in developing strategy and timeline for addressing this issue would be appropriate. NRC and industry should recognize the need to develop a predictable and reliable strategy to address increased reactor coolant inventory events that credits both operator and automatic actions with fully validated procedures; qualified systems, structures, and components; appropriate analyses; and consistent documentation.
cc: Adam S. Gendleman
Enclosure: Increase in reactor coolant system inventory event strategy summary

Entergy Nuke Plant Falling Like Dominos In the South: Waterford

Man, have there been a lot of Turbine trips recently. So Waterford and Grand Gulf have scrammed in recent days and River Bend after a really prolonged outage, seems to be stuck at 87%. 

Power Reactor	Event Number: 54068
Facility: WATERFORD Region: 4     State: LA Unit: [3] [] [] RX Type: [3] CE NRC Notified By: MARIA ZAMBER HQ OPS Officer: DONALD NORWOOD	Notification Date: 05/16/2019 Notification Time: 18:07 [ET] Event Date: 05/16/2019 Event Time: 13:48 [CDT] Last Update Date: 05/16/2019
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL 50.72(b)(3)(iv)(A) - VALID SPECIF SYS ACTUATION	Person (Organization): DAVID PROULX (R4DO)

Unit

SCRAM Code

RX Crit

Initial PWR

Initial RX Mode

Current PWR

Current RX Mode

3

A/R

Y

100

Power Operation

0

Hot Standby

Event Text

AUTOMATIC REACTOR TRIP DUE TO TURBINE TRIP "This is a non-emergency notification from Waterford 3. "On May 16, 2019, at 1348 CDT, Waterford 3 experienced an automatic reactor trip due to Steam Generator number 1 high level, which was the result of a Main Turbine trip and subsequent reactor power cutback which had occurred at 1345 CDT. The cause of the Main Turbine trip is currently under investigation. "Subsequent to the Reactor trip, Main Feedwater Isolation Valves number 1 and number 2 closed on high Steam Generator levels. Emergency Feedwater automatically actuated for Steam Generator number 2 at 1419 CDT and Steam Generator number 1 at 1425 CDT. Main Feedwater was restored to both Steam Generators by 1629 CDT. "The plant entered the Emergency Operating Procedure for an uncomplicated reactor trip and is in the process of transitioning to the normal operating shutdown procedure. The plant is currently in Mode 3 and stable with Main Feedwater feeding and maintaining both Steam Generators. "The NRC Senior Resident Inspector has been notified." All control rods fully inserted. Decay heat is being removed through the main condenser. The plant is in a normal shutdown electrical lineup.