NRC Makes Huge Mistake Publishing Comments in Power Reactor Status Report

(Bet you the leap year was implicated with this???)

The NRC made a rare mistake yesterday. The published the comments  on the power reactor status report. Or did they do this on purpose. They usually wait 30 to 60 days for competitive reason to publish the comments.

My comments about this:

Indian Point 2: The coast down to refueling for the past month has been highly erratic.

Seabrook: Did the maintenence on the 345 line or its downpower cause the scram?

Pilgrim: they explain the computer upgrade has caused its downpower to 98%.

Fermi 2 junk: runback on junk heater drain parts.

Arkansan 2 shutdown: junk check valve parts.

*Grand Gulf: my bad, in refueling outage?

Junk Plant River Bend: problems with breakers. Did the NRC shut them down?

Power Reactor Status Report for March 1, 2016

Unit	Power	Down	Reason or Comment	Change in report (*)	Number of Scrams (#)
Beaver Valley 1	100			*
Beaver Valley 2	100			*
Calvert Cliffs 1	0	02/15/2016	REFUELING OUTAGE	*
Calvert Cliffs 2	100			*
FitzPatrick	100
Ginna	100
Hope Creek 1	100			*
Indian Point 2	81		COASTDOWN TO REFUELING OUTAGE	*
Indian Point 3	100
Limerick 1	94		COASTDOWN TO REFUELING OUTAGE	*
Limerick 2	100
Millstone 2	100
Millstone 3	100
Nine Mile Point 1	100
Nine Mile Point 2	100
Oyster Creek	100
Peach Bottom 2	100		100 MVAR RESTRICTION DUE TO TURBINE BEARING VIBRATIONS
Peach Bottom 3	100
Pilgrim 1	98		HOLDING POWER FOR PROCESS COMPUTER UPGRADE	*
Salem 1	100			*
Salem 2	100			*
Seabrook 1	100		DOWNPOWER CONTINGENCY DURING 345 kV LINE MAINTENANCE
Susquehanna 1	89		COASTDOWN TO REFUELING OUTAGE	*
Susquehanna 2	100			*
Three Mile Island 1	100			*

Region 2

Unit	Power	Down	Reason or Comment	Change in report (*)	Number of Scrams (#)
Browns Ferry 1	100
Browns Ferry 2	100
Browns Ferry 3	0	02/19/2016	REFUELING OUTAGE
Brunswick 1	0	02/26/2016	REFUELING OUTAGE	*
Brunswick 2	100
Catawba 1	100
Catawba 2	100
Farley 1	100
Farley 2	100
Harris 1	100
Hatch 1	0	02/07/2016	REFUELING OUTAGE
Hatch 2	100
McGuire 1	100
McGuire 2	100
North Anna 1	100
North Anna 2	89		COASTDOWN TO REFUELING OUTAGE
Oconee 1	100
Oconee 2	100
Oconee 3	100
Robinson 2	100
Saint Lucie 1	100
Saint Lucie 2	100
Sequoyah 1	100
Sequoyah 2	100
Summer	100
Surry 1	100
Surry 2	100
Turkey Point 3	100
Turkey Point 4	100
Vogtle 1	100
Vogtle 2	100
Watts Bar 1	100
Watts Bar 2	0

Region 3

Unit	Power	Down	Reason or Comment	Change in report (*)	Number of Scrams (#)
Braidwood 1	100
Braidwood 2	100
Byron 1	100
Byron 2	100
Clinton	99		100% ELECTRICAL CAPABILITY
D.C. Cook 1	100			*
D.C. Cook 2	100			*
Davis-Besse	85		COASTDOWN TO REFUELING OUTAGE	*
Dresden 2	100
Dresden 3	100
Duane Arnold	100
Fermi 2	58		RECEIVED POWER RUNBACK FROM LOSS OF HEATER DRAIN FLOW	*
La Salle 1	0	02/14/2016	REFUELING OUTAGE
La Salle 2	100
Monticello	100
Palisades	100
Perry 1	100			*
Point Beach 1	100
Point Beach 2	100
Prairie Island 1	100
Prairie Island 2	100
Quad Cities 1	100			*
Quad Cities 2	91		COASTDOWN TO REFUELING OUTAGE	*

Region 4

Unit	Power	Down	Reason or Comment	Change in report (*)	Number of Scrams (#)
Arkansas Nuclear 1	100
Arkansas Nuclear 2	0	02/23/2016	MAINTENANCE OUTAGE TO REPAIR CHECK VALVE LEAKAGE
Callaway	100
Columbia Generating Station	100
Comanche Peak 1	100
Comanche Peak 2	100
Cooper	100
Diablo Canyon 1	100
Diablo Canyon 2	100
Fort Calhoun	100
Grand Gulf 1	0	02/19/2016	REFUELING OUTAGE
Palo Verde 1	100
Palo Verde 2	100
Palo Verde 3	100
River Bend 1	0	02/17/2016	FORCED OUTAGE - BREAKER MAINTENANCE
South Texas 1	100
South Texas 2	100
Waterford 3	100
Wolf Creek 1	100

Junk Plant Pilgrim's New NRC inspection

That is the problem with the agency. Is their black hole risk determinations low enough to keep a plant safe. The long history of Pilgrim is neither the Entergy or the NRC could correctly determine the risk significance when a problem first emerged like the SRVs.  

Additionally, the inspection assessed whether Entergy’s evaluations into  these significant deficiencies were of a depth commensurate with the significance of the issue,  root and contributing causes of risk-significant deficiencies were identified, and corrective  actions were taken to correct immediate problems and to prevent recurrence.

This is a example of what I am talking about. If you can't trust them to be accurate and have integrity on the little problems then you can't trust them on the bigger issues. The difference between the last blizzard shutdown and the one before is calling the 23kv line operable or inoperable. They called the 23kv line operable in the 2015 blizzard. The 2013 blizzard was called a full Loss Of Offsite Power ( LOOP) while the 2015 blizzard LOOP was called a partial LOOP. If you wanted to take responsibility for the position you place the plant in you would call the 2015 Blizzard  a full LOOP. If you wanted to minimize your responsibilities you would inaccurately call a partial LOOP.

The 23kv line always had way to many uncertainties, as a example Entergy doesn't own or control the quality of the line. There is no equivalencies between a emergency diesel generator and this line. As another example, Entergy because they don't own the line, they have no power to see and understand all the vulnerabilities of the line as in the below NRC example.

Calling the line having the capability to wholly support the plant in a emergency is just a public relation job. You need to always call this line conservatively inop or not available.   

NRC Inspection Report 05000293/2014002 (Agencywide Documents Access and  Management System (ADAMS) Accession No. ML14129A282) documents an NCV  (2014002-02) related to an inadequate procedure for determining operability of the shutdown transformer. Specifically, an NSTAR calculation concluded that certain  alternative offsite power lines did not satisfy Pilgrim’s minimum voltage criteria for the  shutdown transformer, but this information was never incorporated into the degraded  23kV line procedure for determining the operability of the shutdown transformer. 

Entergy procedure EN-LI-102, “Corrective Action Program,” requires Entergy staff to  document the receipt of NRC violations as a CR; however, this did not occur. The  inspectors noted that EN-LI-102 would have likely directed performance of an apparent  cause evaluation and could have prevented the receipt of a second NCV for a similar  issue in 2015. NRC Inspection Report 05000293/2015003 (ADAMS Accession No. ML15317A030) documents an NCV (2015003-03) issued for an inadequate operability assessment of the shutdown transformer because Entergy staff did not appropriately evaluate changes made to the shutdown transformer when an alternate offsite power  configuration was used that resulted in the transformer being inoperable. The inspectors  noted that the degraded 23kV procedure contained incorrect information at that time,  which the operations staff used during the operability evaluation. The inspectors  determined that Entergy’s failure to document NCV 2014002-02 as a CR and perform a  cause evaluation in accordance with EN-LI-102 was a performance deficiency. Because  this issue is an additional contributor to the inadequate operability assessment, and the  enforcement aspects of the inadequate operability assessment are already addressed  as NCV 2015003-03, this issue is not being documented as a separate finding. Entergy

entered this issue into their CAP as CR-PNP-2016-00302 for further evaluation.

Junk Plant River Bend controlled Vessel Level Professionally

Just saying, they started up without fully understanding and fixing the switchyard.

I am happy to see they controlled the reactor level professionally.

Lot of scrams and problems nationally with switch-yards.

I wonder if this well controlled vessel was a function of dumping the feed system, becoming isolated behind MSIVs and using the SRVs to cool the core.    

Automatic Reactor Scram Due toPartial Loss of Offsite Power Caused by Fault in Local 230kV Switchyard
Licensee Event Report 50-458 / 2015-009-00
On November 27, 2015, at 4:31 a.m. CST, with the plant operating at 100 percent power, an automatic reactor scram occurred following the loss of power to both divisions of the reactor protection system (RPS). This condition resulted from a single-phase fault in the local 230kV switchyard. The initial response of the protective relays for the switchyard caused the breakers connected to the north 230kV bus in the switchyard to trip. The fault caused a voltage transient on the in-plant switchgear sufficient to trip the scram relays in the Division 2 RPS, resulting in a half-scram. The action of the protective relays continued, eventually causing the de-energization of reserve station service line no. 1. This lead to the loss of Division 1 RPS and a full reactor scram. The Division 1 and 3 emergency diesel generators started as designed to restore power to their respective safety-related onsite electrical distribution subsystems. Both trains of the standby gas treatment system started, and the primary containment isolation system logic responded as designed. No safety-related systems were out of service at the time of the scram, and reactor pressure and water level were promptly stabilized. All reactor control rods inserted properly. Multiple actuations of the main steam safety-

Seems there was abnormal operation of SRVS. These are rather delicate devices. Will there be future problems with the SRVs: leaking and misoperation. 

relief valves (SRVs) occurred during the event. The nuclear steam supply system vendor reported this action was likely due to a localized pressure transient in the SkV instrumentation lines. SRV tailpipe temperature recorders indicated that all valves re-seated correctly following the initial transient. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an automatic actuation of the reactor protection system, the primary containment isolation logic, and the Division 1 and 3 emergency diesel generators. The root cause of this event remains under investigation. The results of that evaluation will be provided in a supplement to this report.

Junk Perry Plant Vessel Level Control.

The MFP trips and they get a scram. water level declines to the low level scram setpoint. The RFP, HPIC and RCIC starts up and feeds the vessel. Vessel increases so fast it goes to the high level trip. The RFP, HPIC and RCIC trip. This is not control of vessel level. This happened in all these LERs. This is call banging around vessel level.

 

These systems aren't tuned for each other. You are not suppose to get to a low level trip then the high level trip. All these guys got control functions aiming to get level in the mid level or slightly higher. Why doesn't it work as designed?

 

This unprofessional vessel control is distracting the operators from the big picture.     

Enclosed is Licensee Event Report (LER) 2014-005, 

"Loss of Feedwater Results in Automatic Reactor Protection System Actuation".

On November 7, 2014, at 0847 hours, the reactor protection system (RPS) automatically actuated due to a loss of feedwater flow to the reactor pressure vessel (RPV). There were no complications during the shutdown as all control rods fully inserted and pressure was maintained by normal means. The high pressure core spray (HPCS) and the reactor core isolation cooling (RCIC) systems actuated based on a valid low reactor water level initiation and injected to restore RPV water level. 

RPV water level continued to decrease to the Level 2 setpoint (130 inches above TAF) when the RCIC and HPCS systems started and injected into the RPV. Balance of plant isolation occurred with isolation of all required valves. Both reactor recirculation [AD] pumps tripped as designed. The division 3 EDG, which supplies emergency electrical power to the HPCS system started but, as designed, did not load onto the bus. The MFP started as designed on a RFP trip signal. At approximately 0850 hours, the HPCS and RCIC system injections terminated on a Level 8 setpoint (219 inches above the TAF) as designed. The lowest RPV water level reached during the event was 77.2 inches above the TAF. RPS was reset at 0915 hours. Mode 4, Cold Shutdown was entered at 1752 hours. 

CAUSE OF EVENT 

The RPS scram was caused by an invalid feedwater runback signal from the division 1 RRCS. A recorder was installed for additional monitoring purposes and identified signals being injected from the RRCS self-test system (STS) feature into the DFWCS. Data analysis determined that the voltage perturbations correlated to the STS within RRCS. The voltage perturbations had amplitudes of - 66 VDC with pulse durations of - 1 msec. These pulses would repeat in a repetitive pattern between 5 to 7 pulses with noted frequencies varying as short as 130 - 230 msecs. The patterns would occur for a period of - 10 seconds on 2 minute intervals. This signal has a large enough amplitude for actuating the input on the field bus module (FBM); however, the DFWCS software has a 1 scan (200 msec) delay feature to prevent the actuation. A DFWCS runback signal can occur when a signal is in for greater than 200 msecs or these 1 msec pulses align exactly at 200 msec apart. The root cause was determined to be a latent design flaw in the upgrade design package of the DFWCS modification in 2005. Due to implementing the new digital upgrade, the interface between RRCS and DFWCS involving the runback signal was altered. The original design used interposing relays as the interface between the RRCS and the feedwater control system. The digital upgrade changed the design interface and removed the interposing relays tying the output of RRCS directly into DFWCS. 

Enclosed is Licensee Event Report (LER) 2014-004, 

"Loss of Feedwater Results in Automatic Reactor Protection System Actuation". 

On October 20, 2014, at 0217 hours, the reactor protection system (RPS) automatically actuated due to a loss of feedwater flow to the reactor pressure vessel (RPV). There were no complications during the shutdown as all. control rods fully inserted and pressure was maintained by normal means. The High Pressure Core Spray (HPCS) and the Reactor Core Isolation Cooling (RCIC) systems actuated based on a valid low reactor water level initiation and injected to restore RPV water level. 

RPV water level continued to decrease to the Level 2 setpoint (130 inches above TAF) where the RCIC and HPCS systems started and injected into the RPV. Containment isolation occurred with isolation of all required valves. Both Reactor Recirculation [AD] pumps tripped as designed. The Division 3 EDG, which supplies emergency electrical power to the HPCS system started but, as designed, did not load onto the bus. At approximately 0221 hours, the HPCS and RCIC systems and the MFP stopped injecting when the Level 8 setpoint (219 inches above the TAF) was reached. The lowest RPV water level reached during the event was 87.1 inches above the TAF. RPS was reset at 0240 hours. Mode 4, Cold Shutdown was entered at 2323 hours, when the average reactor coolant temperature decreased to 200 degrees Fahrenheit. 

CAUSE OF EVENT 

The RPS scram was caused by an electrical transient in the balance-of-plant (BOP) 120 volt AC Uninterruptable Power Supply (UPS) system [EJ]. At the time of the event plant operators were in the process of shifting the BOP static transfer switch [ASU] to its alternate source for maintenance on the BOP Inverter. The transient was caused by a degraded static transfer switch component. Alternate supply voltage was available but a static transfer failure resulted in a loss of power to the UPS system loads. During the subsequent investigation, it was found that the static transfer switch's alternate power silicon controlled rectifiers (SCRs), were not firing due to an issue from the sensing and transfer card [ECBD]. Without the alternate SCRs firing, no voltage would be provided from the alternate source. Laboratory analysis determined that the card had a degraded logic chip. A NAND gate used in the logic chip was degraded. The degraded NAND gate caused a voltage drop resulting in 6.5V at the input to the downstream logic. This was lower than the expected 15V and failed to generate an "on" signal to the downstream logic. This prevented a firing signal being sent to the alternate source's SCRs. Analysis determined the degradation to be the result of a manufacturing defect. The control logic for the DFWCS is one of the electrical loads serviced by the UPS. Among the loads was an input signal to the RFP availability logic. Disruption of the DFWCS power due to the electrical transient affected the feedwater system causing the control circuit to believe it was not available and drove the output to zero. As a result, feedwater flow was lost to the RPV and the RPS actuated, as designed, when RPV Level 3 was reached. 

Enclosed is Licensee Event Report (LER) 2013-001, 

"Loss of Feedwater Results in Automatic Reactor Protection System Actuation."

On January 22, 2013, at 0332 hours, the reactor protection system (RPS) automatically actuated due to a loss of feedwater flow to the reactor pressure vessel (RPV). There were no complications during the shutdown as all control rods fully inserted and pressure was maintained by normal means. The High Pressure Core Spray (HPCS) and the Reactor Core Isolation Cooling (RCIC) systems actuated based on a valid reactor water level initiation and injected to restore RPV water level. 

The cause of the event was failure of a balance-of-plant inverter/static transfer switch, which provides electrical power to the digital feedwater control system. A circuit card in the static transfer switch degraded, which affected operation of the inverter. The electrical loads serviced by the inverter/static transfer switch were placed on an alternate power source. This alignment will continue until permanent repairs are made which are currently scheduled for the next refueling outage. 

RPV water level continued to decrease and when it reached the Level 2 setpoint (i.e., 130 inches above the TAF), the RCIC and HPCS systems started and injected into the RPV. Both RFPs and the main turbine tripped. Containment isolation occurred with isolation of all required valves. Both Reactor Recirculation [AD] pumps tripped as designed. The Division 3 EDG, which supplies emergency electrical power to the HPCS system started, but did not load onto the bus, as designed. The MFP started as designed when the RFPs tripped. At approximately 0335 hours, the HPCS and RCIC systems and the MFP stopped injecting when the Level 8 setpoint (i.e., 219 inches above the TAF) was reached. The lowest RPV water level reached during the event was 79.8 inches above the TAF. RPS was reset at 0413 hours. Mode 4, Cold Shutdown was entered at 2036 hours when the average reactor coolant temperature decreased to less than 200 degrees Fahrenheit. 

CAUSE OF EVENT 

The RPS scram was caused by an electrical transient in the balance-of-plant (BOP) 120 volt AC Uninterruptable Power Supply (UPS) system [EJ]. The transient was caused by a degraded static transfer switch component [ASU] coincident with a failed DC to AC inverter [INVT]. The static transfer switch did not seamlessly transfer the loads to the alternate source. The inverter was found on the alternate source with the fail light illuminated and its protective fuse actuated. The control logic for the Digital Feedwater Control system (DFWCS) is one of the electrical loads serviced by the UPS. Disruption of the DFWCS logic due to the electrical transient affected the feedwater system by driving the RFP controllers to minimum flow with no start signal being sent to the MFP per design. As a result, feedwater flow was lost to the RPV and the RPS actuated, as designed,when RPV Level 3 was reached.

Junk Plant Perry Gets Special inspection over Multiple Events

05000440


Way before the event that caused the special inspection, I documented I felt Perry was heading for trouble. Here is how I preemptively I documented my concerns. 

 

• Junk Plant Fermi Can't File A Clean Event Report

"Here I am today (2/29)just before the special inspection was announced. I thought it fishy Perry was admitting all the inaccurate event reports on the same swipe. Bet you Perry thought the special inspection inspector outsiders wouldn’t have the same deal as the onsite residents. We will ignore all initial event report mistakes and inaccuracies. So Perry came clean on their own.  

Perry must have been notified many days ago a special inspection was coming to their plant."   

• Perry Is or Getting Sloppy?

(originally posted on 2/2) FRIDAY, FEBRUARY 12, 2016
"So about 17 days from this Jan 29 leak and reactor vessel control fumbling...we got this new scram on two SRVs opening up.

NRC: you happy about this?"
• Junk Plant Perry During Start-up Had Another Complicated Trip

• Junk Perry-Extremely Infrequent Event With Two SRVs Opening At Power

(2/9 and 2/12)"I am disappointed the manual scam didn't come sooner. This is such a rare event, I am not sure their emergency procedures carry a specific event with two SRVs slamming open. You would think this is a so rare event and they never trained on it, they would emediately scram the plant.  This guy is so infrequent it calls for a special inspection."

(February 29, 2016) NRC Begins Special Inspection at Perry Nuclear Plant

The Nuclear Regulatory Commission has launched a Special Inspection into two recent events, neither of which affected public health or safety, at the Perry Nuclear Power Plant. The plant is operated by FirstEnergy Operating Co., and is located in Perry, Ohio, about 35 miles northeast of Cleveland.

Sounds like they didn't have valve position indication. They surmised SRVS were open because torus temperatures were screaming up.    

On February 8, operators manually shut down the reactor when they observed an increase of the temperature in the suppression pool. The suppression pool is designed to condense steam and is also a water source for emergency cooling systems. While the reactor was shutdown, on February 11, there was a temporary loss of power to certain plant cooling equipment.
 Operators were able to use a redundant system and restore power to the cooling systems.

“Even though the two events are not related we have questions related to the response of the equipment and operator actions. Our team of specialists in reactor operations and electrical equipment will review the technical details to better understand what happened,” said NRC Region III Administrator Cynthia D. Pederson.

A fairly large size team.  

The four-member inspection team began work on Monday and will spend time both on and off site conducting their reviews. After the inspection, a report documenting the team’s findings will be made publicly available.

Junk Plant Indian Point 2 Has Worst Capacity Factor Than River Bend

Seems they been stuck at 90% for more than a week?

Junk Plant Fermi Can't File A Clean Event Report.

This events were updated on Friday. Basically the RPS was supposed to be declared inop when these events occurred. This is very unprofessional. 

They assume the first time (1/06/2016) it was a actuator problem. 

Power Reactor	Event Number: 51755
Facility: FERMI Region: 3 State: MI Unit: [2] [ ] [ ] RX Type: [2] GE-4 NRC Notified By: DEREK ETUE HQ OPS Officer: JOHN SHOEMAKER	Notification Date: 02/25/2016 Notification Time: 16:35 [ET] Event Date: 01/06/2016 Event Time: 15:14 [EST] Last Update Date: 02/25/2016
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(A) - POT UNABLE TO SAFE SD	Person (Organization): ANN MARIE STONE (R3DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
2	N	Y	100	Power Operation	91	Power Operation

Event Text

POWER REDUCTION DUE TO AUTOMATIC OPENING OF THE TURBINE BYPASS VALVES "On January 6, 2016. at approximately 1514 EST, with Fermi 2 in Mode 1 operating at 100 percent reactor thermal power, the East and West Turbine Bypass Valves (TBVs) automatically opened for 3 minutes and 32 seconds in response to the number one High Pressure Turbine Stop Valve (TSV) drifting from full open to 25% open. Reactor power was subsequently lowered to 91.0 percent reactor thermal power and the bypass valves closed. "Per Technical Specification Bases 3.3.1.1, TBVs must remain shut while reactor thermal power is at or above 29.5 percent to consider the TSV closure and Turbine Control Valve (TCV) fast closure Reactor Protection System (RPS) functions operable. The condition was recognized at the time of the event and the RPS functions were not declared inoperable since the functions were verified to remain enabled. "Since the RPS functions were not declared inoperable, Fermi 2 did not report this event within 8 hours of occurrence. However, after further evaluation, it was determined that this event met the reporting criterion. Accordingly, this event is being reported pursuant to 10 CFR 50.72(b)(3)(v)(A). "The licensee informed the NRC Resident Inspector." The cause of the High Pressure Turbine Stop Valve drifting was due to an actuator malfunction that has since been corrected. This event was determined to be reportable at 1200 EST on 02/24/16. See EN #51756 for a similar event that occurred on 02/21/16.

This is the second time (2/02/1016) the turbine bypass flings open? 

It is now called a "communication card failure" not a actuator problem. 

Power Reactor	Event Number: 51756
Facility: FERMI Region: 3 State: MI Unit: [2] [ ] [ ] RX Type: [2] GE-4 NRC Notified By: DEREK ETUE HQ OPS Officer: JOHN SHOEMAKER	Notification Date: 02/25/2016 Notification Time: 16:35 [ET] Event Date: 02/21/2016 Event Time: 00:30 [EST] Last Update Date: 02/25/2016
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(A) - POT UNABLE TO SAFE SD	Person (Organization): ANN MARIE STONE (R3DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
2	N	Y	100	Power Operation	91	Power Operation

Event Text

POWER REDUCTION DUE TO AUTOMATIC OPENING OF A TURBINE BYPASS VALVE "On February 21, 2015, at approximately 0030 EST, with Fermi 2 in Mode 1 operating at 100 percent reactor thermal power, the West Turbine Bypass Valve (TBV) automatically opened in response to the number two High Pressure Turbine Stop Valve (TSV) cycling from full open to closed and then to 22 percent open. Reactor power was subsequently lowered to 91.5 percent reactor thermal power and the bypass valve closed. "Per Technical Specification Bases 3.3.1.1, TBVs must remain shut while reactor thermal power is at or above 29.5 percent to consider the TSV closure and Turbine Control Valve (TCV) fast closure Reactor Protection System (RPS) functions operable. The condition was recognized at the time of the event and the RPS functions were declared inoperable. The Limiting Condition for Operation was exited at 0031 EST following TBV closure. "Since the RPS functions were verified to remain enabled, Fermi 2 did not report this event within 8 hours of occurrence. However, this event was subsequently determined to meet the reporting criterion and is being reported pursuant to 10 CFR 50.72(b)(3)(v)(A). "The licensee informed the NRC Resident Inspector." The cause of the High Pressure Turbine Stop Valve cycling was due to a communication card failure that has since been corrected. This event was determined to be reportable at 1200 EST on 02/24/16. See EN #51755 for a similar event that occurred on 01/06/16.

Again not reporting accurate event reports. 

MANUAL SCRAM DUE TO LOSS OF TURBINE BUILDING CLOSED COOLING WATER

It starts out as a leak in the Turbine Building Closed Cooling> So this event occured on Sept 13 and it takes them all this time to fix the event report. Sounds like the NRC provoking Femi to fix inaccurate 

"At 2305 EDT on September 13, 2015, a manual scram was initiated in response to a loss of all Turbine Building Closed Cooling Water (TBCCW). All control rods fully inserted. The lowest Reactor Water Level (RWL) reached was 137 inches. All isolations and actuations for RWL 3 occurred as expected. Decay heat was initially being removed through the Main Turbine Bypass System to the Main Condenser, however, as a result of the loss of TBCCW, the Main Feed Pumps lost cooling and had to be secured. At 2310, Standby Feedwater was initiated and Main Feedwater was secured.

"The loss of TBCCW also caused all Station Air Compressors (SACs) to trip on loss of cooling. The loss of SACs caused the Instrument Air header pressure to degrade to the point at which the Secondary Containment isolation dampers drifted closed. This resulted in the Reactor Building vacuum exceeding the Technical Specification limit. At 2325, operators started the Standby Gas Treatment system and manually initiated a Secondary Containment isolation signal. Secondary Containment vacuum was promptly restored to within Technical Specification limits. Additionally, Operators were monitoring for expected MSIV drift due to the degraded Instrument Air header pressure. When outboard MSIVs were observed to be drifting, Operators closed the outboard and inboard MSIVs at 2345. At 2352, Safety Relief Valves (SRVs) reached the Low-Low Setpoint and began cycling to control reactor pressure.

"RWL is currently being maintained in the normal level band with the Standby Feedwater and Control Rod Drive systems. Reactor Pressure is being controlled with Safety Relief Valves. Operators are currently in the Emergency Operating Procedure for Reactor Pressure Vessel control. Investigation into the loss of TBCCW continues.

"No safety-related equipment was out of service at the time of the event. All offsite power sources were adequate and available throughout the duration of the event.

"The NRC resident inspector has been notified."

* * * UPDATE AT 0555 EDT AT 09/14/15 FROM CHRIS ROBINSON TO JEFF HERRERA * * *

"At 0409 EDT the Reactor Core Isolation Cooling (RCIC) system was placed in service due to identification of an unisolable leak in the Standby Feedwater System. Reactor water level and pressure is now being controlled though the RCIC system and Safety Relief Valves. This event update is reportable as a valid manual initiation of a specified safety system under 10CFR50.72(b)(3)(iv)(A).

"The NRC resident inspector has been notified."

The leak rate was reported as approximately 5-10 gallons per minute from a weld on the standby feedwater pump header drain valve F326. The licensee reported the leak stopped once RCIC was placed into service. The licensee is still investigating the issue.

Notified the R3DO (Pelke), IRD Manager (Grant), NRR EO (Morris).

* * * UPDATE PROVIDED BY CHRIS ROBINSON TO JEFF ROTTON AT 2135 EDT ON 09/14/2015 * * *

"At 1847 EDT on September 14, 2015, a valid automatic Reactor Protection System (RPS) actuation occurred due to Reactor Water Level 3 while shutdown in MODE 3. Operators were manually controlling Reactor Pressure Vessel (RPV) level and pressure with Reactor Core Isolation Cooling (RCIC) and Safety Relief Valves (SRV). While operators were cycling SRVs, the RPV level went below the Level 3 setpoint. Operators promptly restored RPV level by manual operation of RCIC. The Level 3 actuation and associated isolations were verified to operate properly.

"The scram signal has been reset. Fermi 2 remains in MODE 3 controlling RPV Level and Pressure through manual operation of RCIC and SRVs.

So they got a scram on cycling SRV valves twice. It indicates problems with training.  

"This is the second occurrence of a valid specified safety system actuation reportable under 10CFR50.72(b)(3)(iv)(A) for this ongoing event.

"The NRC Resident Inspector has been notified."

Notified R3DO (Riemer), IRD Manager (Grant), and NRR EO (Morris)

* * * UPDATE FROM BRETT JEBBIA TO JOHN SHOEMAKER AT 1446 EST ON 2/27/16 * * *

"This update provides clarification of the applicable reporting criteria for this Event associated with primary containment isolation actuations.

"Upon the manual reactor scram at 2305 EDT on September 13, 2015, Reactor Protection System (RPS) Level 3 actuated and Primary Containment Isolation System (PCIS) Groups 4, 13 and 15 actuated as expected. The applicable reporting criterion for these actuations is 10 CFR 50.72(b)(3)(iv)(A).

"The applicable reporting criterion for the manual closure of the inboard and outboard main steam isolation valves at 2345 EDT on September 13, 2015, is also 10 CFR 50.72(b)(3)(iv)(A). In addition, the manual closures of all MSIV lead to a loss of condenser vacuum which resulted in the actuation of PCIS Group 1 at 0001 EDT on September 14, 2015, as expected. The applicable reporting criterion for this actuation is also 10 CFR 50.72(b)(3)(iv)(A).

"Upon reaching Level 3 at 1847 EDT on September 14, 2015, PCIS Groups 4, 13 and 15 actuated as expected. The applicable reporting criterion for this actuation is 10 CFR 50.72(b)(3)(iv)(A).

"The licensee informed the NRC Resident Inspector."

Notified the R3DO (Stone).

PSEG: New Official at Junk Nuclear Fleet Operator?

Can he straighten out and fix the junk?

Or is he going to help run it until it can't be fixed any more, or not worth fixing?

Here we can see the symbioses of the military, working as a NRC resident inspector and becoming a senior executive of a fleet operator...

Why did he pick such a small fleet operator with all his big credentials?

 

PSEG names nuclear industry veteran president of PSEG Nuclear

By Emily Bader, February 26, 2016 at 1:25 PM
PSEG named Peter Sena president of PSEG Nuclear. - (PSEG)

Newark-based PSEG announced Friday that it has named Peter Sena president of PSEG Nuclear, effective in late March.

Sena, a nuclear industry veteran, will report directly to William Levis, president of PSEG's Power business. Robert Braun, chief nuclear officer, will report to Sena.

Sena served as chief nuclear officer at First Energy Corp. Most recently, he was senior vice president of operations and chief operating officer at NextEra. In his early career, he was an engineering officer with the U.S. Naval Nuclear Propulsion program and also served as a resident inspector with the Nuclear Regulatory Commission.

"We are very pleased to have Pete join PSEG as President of the Nuclear business," Levis said in a prepared statement. "His proven track record of creating sustainable excellence at multiple nuclear facilities over the years — which was recognized by INPO Excellence awards multiple times — will be a tremendous asset to our business. His broad experience in the industry both as a representative on key task forces and as a leader at First Energy and NextEra makes him an ideal candidate for the role."

"I'm excited to join PSEG Nuclear at such a critical time in the market," Sena said in a prepared statement. "I look forward to working...

PSEG – Public Service Enterprise Group Inc.: PSEG Names Nuclear Industry Veteran, Peter Sena, President of PSEG Nuclear 

Tickers: PEG 

(February 26, 2016 - Newark, N.J.) - PSEG announced today that it named a nuclear industry veteran, Peter Sena, President of PSEG Nuclear. Sena will report to William Levis, President of PSEG's Power business. Robert Braun, Chief Nuclear Officer, will report to Sena. Sena will join PSEG in late March. 

Sena served as Chief Nuclear Officer at First Energy Corporation culminating a 15-year career in a variety of leadership roles at First Energy nuclear operations. Most recently, he was Senior Vice President of Operations, COO at NextEra. 

'We are very pleased to have Pete join PSEG as President of the Nuclear business,' said Levis. 'His proven track record of creating sustainable excellence at multiple nuclear facilities over the years --which was recognized by INPO Excellence awards multiple times -- will be a tremendous asset to our business. His broad experience in the industry both as a representative on key task forces and as a leader at First Energy and NextEra makes him an ideal candidate for the role.' 

'I'm excited to join PSEG Nuclear at such a critical time in the market,' Sena said. 'I look forward to working with this team to help realize the full potential of the PSEG nuclear operations.' 

In his early career, he was an Engineering Officer with the U.S. Naval Nuclear Propulsion program for six years as well as serving as a Resident Inspector with the Nuclear Regulatory Commission.

Deep in the nuclear industries intelligentsia...

Sena is a graduate of Penn State with a degree in Fuel Science and recently served as a Penn State Nuclear Engineering Advisory Board Member and currently serves on the Auburn University's Advisory Board. In addition, he has recently served on the INPO Executive Advisory Committee and the Nuclear Energy Institute (NEI) Nuclear Strategic Issues Advisory Committee where he was the Industry Executive Sponsor of the NEI post Fukishima flooding response initiative. 

More Safety Breaker Problems at Junk Plant River Bend.

So where is the reset button to make a plant, fleet, employees and management all new. Where is your reset?  We all deserve a second, third, forth and fifth chance. So where is our next second chance? 

I like riding my mountain bike in the small mountains around my house. I spend a tremendous amounts of time on my bike seat. Being outdoor and in nature reminds me how close we all are to the infinite and god. It is just right there without any deniability. I am heading out to the infinite right now.

It is like coming to a swampy area on my bike. Five or six mosquitoes are on my arm and many more attached to my body. I am getting extremely uncomfortable. I can imagine itching for hours. It's like swatting one mosquito to death on my arm and wondering why I am still being attacked by a cloud of bugs. I should be not thinking stupid thoughts at all, but moving my bike(me)bike out of the swamp.

Honestly, I would never give up on the human spirit and our intelligence. The ability of people to dig a hole nobody can imagine them getting out of. The ability of person at any point, to transform their lives. We are all one higher choice away from a world we dream of. Maybe it not dream at all, but a world god provides for us. It is our choice.  

I don't think this event went down this way they said it did. I think Entergy was worried the NRC would request a shutdown. Or the NRC hinted they might do that. 

Basically by March of 2015 the NRC and Entergy realized they have systemic breaker quality and reliability issues at River Bend. It is unbelievable after all this time and the special inspection, they would discover new breaker problems at River Bend. 

What would a plant reset look like to you?            

Power Reactor	Event Number: 51754
Facility: RIVER BEND Region: 4 State: LA Unit: [1] [ ] [ ] RX Type: [1] GE-6 NRC Notified By: JACK McCOY HQ OPS Officer: STEVE SANDIN	Notification Date: 02/24/2016 Notification Time: 18:16 [ET] Event Date: 02/24/2016 Event Time: 11:00 [CST] Last Update Date: 02/24/2016
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(A) - POT UNABLE TO SAFE SD	Person (Organization): JACK WHITTEN (R4DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	N	0	Cold Shutdown	0	Cold Shutdown

Event Text

ELECTRICAL BREAKER ISSUE IDENTIFIED DURING AN ENGINEERING REVIEW "At 1100 CST on February 24, 2016, with the plant in cold shutdown (Mode 4), the shift manager was notified of a condition that could potentially prevent the automatic closure of the circuit breakers powering the emergency ventilation fans in the both the Division 1 and 2 emergency diesel generator rooms. These fans are not in Technical Specifications, however, they provide a support function to the emergency diesel generators, requiring that both diesel generators to be declared inoperable. This inoperability constitutes a condition that could potentially prevent fulfillment of the safety function of onsite AC power sources, and is being reported pursuant to 10 CFR 50.72(b)(3)(v). "Four additional breakers are affected by the same condition. These breakers supply power to Division 1 and 2 containment unit coolers and the Division 1 and 2 auxiliary building 141 ft. elevation general area unit coolers. The auxiliary building unit coolers are not in Technical Specifications, however, they provide a support function to the electrical distribution system. The Technical Specification required action is to declare both trains of the residual heat removal system (shutdown cooling mode) inoperable. This inoperability constitutes a condition that could potentially prevent the fulfillment of the decay heat removal safety function, and is being reported pursuant to 10 CFR 50.72(b)(3)(v). "Division 2 residual heat removal is operating in shutdown cooling, satisfactorily maintaining reactor coolant temperature. The affected breakers can be manually operated to start/stop their associated equipment, if necessary for operation." This condition was identified during an Engineering review. The licensee has compensatory measures in place. Long term corrective actions are under review. The licensee informed the NRC Resident Inspector.

Special Inspection at River Bend: The Chiller Thriller

(Feb 24, 2016@ 5pm) "Yea well, right after the 2014 Christmas plant trip I noticed the troubles River Bend was having controlling vessel water level. Don’t even get me talking about all the plant trips nationwide in the industry, with them having feedwater control system problems. My favorite recently is Callaway. They partially reverse-engineered an obsolete aux feed water safety controller cards. It is cheaper to replace a card than replace the system (“Failure to assure that the design of the replacement reverse engineered Modutronics controller cards for the auxiliary feedwater control valves were suitable for their application”). 

So I looked at a bunch of LERs about plant trips at River Bend. In most of the trips, the level was unprofessionally banging from the high feed pump trip to the low level scram. I doubt you could call it control. The feed pumps were constantly tripping also. I just couldn’t believe how they were getting away with acting so unprofessional scram after scram. So I made out notes on my blog…I talked to the senior resident explaining the problem. He flipped it into an allegation, I hate the NRC’s allegation
department. They in turn called a special inspection. They discovered known massively leaking feed regulating valves and the simulator had serious fidelity problems. No wonder they didn’t know how to control reactor vessel level. Here is the NRC’s response to me. 

“NRC: Proof I instigated The 2014 Christmas River Bend plant Scram Special Inspection” 

In this response, the NRC says in investigating my vessel level problem, the NRC discovered an almost identical issue with ventilation breaker. The NRC said I caused two special inspections. It startles me to death to think the licensee and NRC can’t figure this out without an outsider provoking them. 

“Junk Plant River Bend’s Crazy February 2016 Power History So Far...” 

Here I am explaining River Bend’s disgusting recent capacity factor problems on my blog. I again called the senior resident inspector. Basically she told me the down-powers and shutdowns are caused by a host of equipment problems. She wouldn’t get specific. She won’t tell me why they shutdown on Fed 16. River Bend is in a lot more trouble than the ROP and inspection reports disclose. 

Since the 2014 Christmas trip River Bend has had three special inspections. It’s got to be a record. The three special inspections are: the 2014 Christmas scram, the magniblast breaker issue and the recent lightning scram where they flubbed putting on shutdown cooling. I am dying to see if River Bend controlled vessel level in the lightning scram?

NRC Allegation response to me: “Based on the multiple failures of the feedwater system, the potential generic concern with the Magne Blast circuit breakers, and the issues related to reactor vessel level between the Level 3 (low) and Level 8 (high) setpoints following a reactor scram, the NRC determined that the appropriate level of NRC response was to conduct a special inspection.”"

Junk Plant Hope Creek: PSEG's Frivolous Denial Of NRC Non Sited Violation

works in progress

Originally posted 2/28

I have felt guilty for weeks with not commenting on this inspection report and the licencee not accepting the NRC's minimalist finding. They are wasting the NRC's time and their own. 

Basically the industry has been recently trying to dial down the CDBI inspections in regulatory reduction. It is as wasting everyone's time.

I think the gist of this stupid is Hope Creek violation was preforming a intentional experiment on the plant. The NRC gave Hope Creek a gift...then they wouldn't accept the gift. They were having troubles with this valve for years with leaking and they didn't have a adequate safe replacement. They gambled if they turned the valve around from normal...had the flow holding the valve shut against pressure, it would fix the leak. They valve was never designed for this duty, basic engineer work...so there was much more friction opening and closing this valve.

I think this is a symtom of a attitude problem with Hope Creek, they are trying to disrupt and weaken NRC authority and oversight over frivolous non sited violation regulatory disputes. It like a cop stops you for speeding and he then lets you off with just a verbal warning.  

February 9, 2016

SUBJECT: RESPONSE TO DISPUTED NON-CITED VIOLATION HOPE CREEK GENERATING STATION – COMPONENT DESIGN BASES INSPECTION REPORT 05000354/2015007 

Dear Mr. Davison: 

We received your response [ADAMS No. ML15362A564] to our inspection report

 05000354/2015007 [ADAMS No. ML15329A157] issued on

• Denial of NCV 05000354/2015007-02, Inadequate Work Order Instructions and Drawings Resulting in Improper Installation of a Safety-Related SW Valve

• HOPE CREEK GENERATING STATION – COMPONENT DESIGN BASES INSPECTION REPORT 05000354/2015007

November 25, 2015, concerning activities conducted at your facility. In your response, you denied a Non-Cited Violation (NCV) contained in the inspection report. Specifically, PSEG contends that “the weaknesses identified in the inspection report regarding classification, evaluation and corrective actions are not more than minor in that PSEG’s conclusion on operability and corrective actions were not impacted.” 

The NRC conducted a detailed review of your response and the applicable inspection guidance. Region I staff who were not involved with the initial inspection effort performed this review. After careful consideration of the bases for your denial of the NCV, we determined that the violation and characterization of the finding were properly described in the inspection report. Specifically, the inspection team identified that your staff failed to conduct operability determinations in October 2013 following the improper installation of a service water system valve and a subsequent event where the valve failed to operate due to a high torque condition. In response to the inspection team’s questions, your staff, with support from an external engineering organization, performed an operability review and determined that the valve was able to perform its safety function for a limited number of operating cycles. You subsequently scheduled a maintenance activity to fully restore the valve during the October 2016 refueling outage. Our review determined that this finding was appropriately characterized as “more than minor” as there was a reasonable basis for questioning operability of the valve following the October 2013 events described above. We have provided a summary of our evaluation and conclusions as an enclosure to this letter. 

SUMMARY  

Non-Cited Violation (NCV) 05000354/2015007-02

Restatement of the Violation:

The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, “Instructions, Procedures, and Drawings,” because PSEG did not provide adequate work order instructions for the installation of service water (SW) pump discharge isolation valve 2198C following planned valve maintenance in October 2013. Specifically, the inadequate work order instructions contributed directly to maintenance technicians installing the valve in the opposite orientation compared to the intended orientation.

Licensee Response (Summary): 

PSEG denies that the NRC identified any new information that impacted the licensee’s conclusions regarding operability or corrective actions. The improper re-installation of the valve EAHV-2198C was promptly identified by the licensee and entered in CAP, and the additional analyses performed in response to NRC questions supported the licensee’s initial conclusions. 

In addition, PSEG contends the identified weaknesses associated with the classification, evaluation, and corrective actions of EAHV-2198C do not meet the threshold for more than minor.

NRC Evaluation: 

The NRC Region I staff performed an independent review of the documented NCV in Inspection Report 05000354/2015007, using PSEG’s basis for denial for comparison, and made the following observations:

1) Notification (NOTF) 20626219 was initiated by the PSEG staff on October 22, 2013, identifying the installation of valve 2198C 180 degrees different than when removed. This NOTF was subsequently updated by the PSEG maintenance staff to reflect inadequacies in the applicable Work Order (60112463-410) as compared to the valve drawing (M-10-1) and the associated vendor manual. The NCV properly refers to 10 CFR 50, Appendix B, Criterion V, as the appropriate violation of regulatory requirements.

2) The Component Design Bases Inspection (CDBI) report states (page 6) that “there was no documented evaluation of the impact of this misalignment and configuration error prior to operations declaring the C SW pump operable following the 2198C maintenance on October 23.” As stated in the report and further clarified by interview with the inspection team leader, PSEG did not complete an operability evaluation prior to restoration of the C SW pump to service on October 23, 2013, in spite of the improper installation of the outlet valve. Further, PSEG acknowledged this deficiency by initiating NOTF 20705874 (also documented in the report). The inspection report (page 7) identified a second instance where PSEG failed to properly assess a valve operational anomaly, an unexpected high opening torque (compared to the valve’s weak link analysis and Limitorque limits) and its potential adverse impact on system operability.This condition was identified during troubleshooting of valve 2198C on October 27, 2013, but no corresponding operability evaluation was documented.

3) The team’s observations documented in the report and highlighted in 2) above, form the basis for the inspection team’s conclusion that the NRC added value to a licensee-identified finding or violation. The absence of an operability evaluation, for either of the above referenced conditions, was documented as a “weakness in the licensee’s classification, evaluation, or corrective action” (page 9) and was the basis for the team to conclude there was a reasonable doubt of operability, with respect to the valve being able to function under all design basis conditions. In order to conclude that the valve was operable and to answer questions from the inspection team, PSEG performed an operability determination for the issue of the valve being installed in the wrong orientation (NOTF 20705874), performed a technical evaluation to determine that the valve actuator was capable of opening the valve under all required design basis conditions based upon actual measured data (NOTF 20704783), and contracted with Kalsi Engineering to perform an H4BC gear box torque analysis for the valve actuator. This team conclusion was documented in the Analysis Section of the inspection report (page 9-10) in reference to the basis for the observations (and underlying performance deficiency) being more than minor. The team cites Example 3.j of IMC 0612, Appendix E, as justification of the more than minor determination. 

4) PSEG’s Basis for Denial did not address the Appendix E more than minor example referenced in the CDBI inspection report. Rather, PSEG stated that the weaknesses identified by the team regarding classification, evaluation and corrective action were not more than minor. Further, PSEG contends that the additional analyses performed in response to NRC team questions did not change the original operability determination outcome. Neither the subjective contention of the weaknesses being minor nor the final determination of operability being maintained provide a sufficient basis for denial. The NRC determined that the Appendix E example established the basis for determining that this performance deficiency was of more than minor significance.

5) In the Basis for Denial, PSEG opines that the CDBI team’s challenge of the operability impact of the above conditions was unfounded without knowledge of the actual operating conditions of the system (system alignment, flowrates, and valve differential pressure were not recorded and were unknown). PSEG contends that without knowing actual system operating conditions, data cannot be extrapolated with any certainty. The NRC considers that the uncertainties associated with the valve operating parameters highlight the reason why PSEG was required to perform an operability determination following improper installation of the valve and its failure to operate due to a high torque condition.

6) Additionally, PSEG took exception to the observation in the inspection report that the maintenance work instructions lacked sufficient detail. On page 6 of the inspection report, the inspection team noted that PSEG maintenance personnel identified and documented in NOTF 20626219, that the desired orientation of the 2198 valve was not specified in valve drawing M-10-1 or in the vendor manual. The inspection team also noted that the work order contained several diagrams which depicted the wrong valve orientation. The NRC determined that the maintenance work instructions given to the maintenance staff lacked sufficient detail to ensure that the valve was installed in the proper orientation.

For the above reasons, the staff concludes that the violation occurred as described in Inspection Report 05000354/2015007.