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

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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?