River Bend: Why are all these component failures and human errors in the same scram?

The NRC recently verified my analyses of this event. I was shockingly spot on correct...

The long delayed Mike Mulligan River Bend special inspection came out.

 I think River Bend needs mandatory testing...giving the plant the worst scram to see how the operators, procedures and all the equipment responds. Plant scram testing if you will. One should have occurred a first startup after the 2014 Christmas scram and the other near the outage to test all the operator and equipment at full decay heat load. Simulators are a amazing inventions...but they have their limitation. A simulator just doesn't carry this.   
 Originally published on 1/28/2016...

First pump published on Jan 29. Republished. 

I am happy they are going to be looking into vessel control.  

Jan 27: The Nuclear Regulatory Commission has begun a special inspection at the River Bend Station nuclear power plant to review circumstances surrounding an unplanned reactor shutdown that occurred on Dec. 25, 2014.
The plant, operated by Entergy Operations, Inc., is located in St. Francisville, La. 

The plant was operating at 85 percent capacity Christmas morning when an unplanned shutdown with complications occurred. 

Following the shutdown some problems were experienced with the plant's feedwater system, which supplies short-term cooling water to the reactor core, as well as several electrical circuit breakers. Operators took compensatory action to ensure the plant would remain in a safe shutdown mode. 

"The purpose of this special inspection is to better understand the circumstances surrounding the event, determine if there are any generic implications, and review the licensee's corrective actions to ensure that the cause of the event, including associated equipment problems have been effectively addressed," NRC Region IV Administrator Marc Dapas said. 

Several NRC inspectors will spend about a week on site evaluating the licensee's root cause analysis, maintenance of some plant systems and adequacy of corrective actions. An inspection report documenting the team's findings will be publicly available within 45 days of the end of the inspection.

At least a maintenance problem didn't take out another feed pump...it was a plant employee taking out all the demineralizers.

The should replace the feed reg valve and the feed system control systems.

Hmm, no RFP trips on vessel water swell? That is how all scrams should go. Seems the operators killed two MFP, then a plant employee killed the other MFP. This proves it is something in the training...it is not cycling the SRVs or swell from that. It is controllable. 

It is the slow acting FRV or leaking FRV from having the MFP on or all of them on.  

River Bend: Licensee Event Report50-458 / 2014-002-00

Reactor Scram Due to Average Power Range Monitor High-flux Signal Following a Malfunction of the Main Turbine Electrohydraulic System.

During the upcoming refueling outage in February 2015, an evaluation of a potential replacement of the obsolete card will b2 completed. A complete replacement with a digital EHC system is planned for the refueling outage to occur in early 2017. These actions are being tracked in the corrective action program.

Jan 5,

The River Bend NRC senior resident inspection gave me a call today. Another submarine brother. Most surprising out of the talk, he hasn't yet got boned up on the RB historical factors that caused this Christmas event like turbine control, vessel level management or the continued problems with feed water pumps in his LERs and inspection reports.

We talked about all the troubles with River Bend, ANO, Palisades, VY and pilgrim...how Entergy is always in the NRC's news at 11 pm tv station.

I told him, you know what irks us; like when they have component failures and vessel level management over and over again, and you can't get control of these guys. I think we and the NRC's Washington management victimizes he resident inspector...we don't give you the tools and power to control these guys.  

The agency is deciding if it going to be another River Bend special inspection...can I knock them into a special inspection?

What was cool, I had this page up and running on the internet before he called. We went though this article like my talking points and it was up in his computer? 

When I talked about the poor turbine grounding and the buildup of static electricity leading to erratic instrumentation readings and RPS trips...he kinda got quiet for a second. I think we are back to turbine grounding issue.

I do have to give great credit to the NRC...they do call me back.       

River Bend always has had a lot of NRC violation. A plant is not in a very healthy condition when they get a scram, then they get a lot of components breakdowns and employee errors in the scam. 

Lets see if I can interpret what happened?  

As far as the vessel repeatedly going out high on swell in every scram at 100%...I don't buy it for one second. They got a poorly optimized feed regulation valve system or it is poorly designed. They probably got the system half ass optimized so they would rather have a high level vessel feed water pump trip and scram, than a scare the pants of everyone low vessel level scram or low low level. The feedwater regulation valves and control system don't operate quickly enough to follow a down-power transient OR scram...they over feed the vessel. The feed water valves close too slowly!

There will be hell to pay if a huge chunk of water ends up going down the main steam lines...there will be a terrific water hammer outside the design of the plant. This could lead to bigger problems with cooling the core down too fast. Excessively feeding the vessel and cooling down the core adds a lot of reactivity.   

Power Reactor Event Number: 50704

Facility: RIVER BEND
Region: 4 State: LA
Unit: [1] [ ] [ ]
RX Type: [1] GE-6
NRC Notified By: DANIEL PIPKIN
HQ OPS Officer: DANIEL MILLS Notification Date: 12/25/2014
Notification Time: 12:41 [ET]
Event Date: 12/25/2014
Event Time: 08:37 [CST]
Last Update Date: 12/25/2014
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):
THOMAS FARNHOLTZ (R4DO)
Unit SCRAM Code RX CRIT Initial PWR Initial RX Mode Current PWR Current RX Mode
1 A/R Y 85 Power Operation 0 Hot Shutdown
Event Text
AUTOMATIC REACTOR SCRAM 

"At 0837 [CST] on 12/25/14, a loss of Reactor Protection System (RPS) 'B' occurred which resulted in a Division 2 RPS half SCRAM. This occurred concurrent with a Division 1 RPS half SCRAM which had been inserted for LCO 3.3.1.1 Action 'A' due to issues with the #2 turbine control valve RPS logic on 12/23/14. This resulted in a full RPS actuation and Reactor SCRAM. During the SCRAM, a reactor water Level '8' occurred which tripped the running reactor feed pump. Reactor water level peaked at 56 inches. This Level '8' is under investigation. Once reactor water level lowered below 51 inches the Level '8' signal was reset, and the team attempted to start the 'C' reactor feed water pump. 

"The 'C' reactor feed pump failed to start upon attempt. The 'A' reactor feed pump was then started successfully. The startup feed regulating valve failed to open in automatic or manual mode, resulting in an RPV Level '3' signal (lowering to 8.1 inches). The operators manually aligned the 'C' feed water regulating valve and restored reactor water level to normal band. The plant is stable in Mode 3 pending investigation." 

1) Had some kind of warning light or maybe a half scram on the "#2 turbine control valve RPS logic on 12/23/14" indicating some instrumentation components was failing (the issues).
 

2)I&C put in a Div 1 and A RPS in a half scam...must have been doing some testing or repair. This assures on a "B" trip you will get a full scram. Usually on a half a scram, it is not enough to get a scram.
 

3) Then they got a "B" RPS trip on a #1 turbine control valve RPS logic.

4) The reactor lever went high leading to a reactor water lever "8' trip. This tripped all the feed pumps. The reactor water level was increasing out of control high. They didn't want water going down their steam line. This is unprofessional not being able to control reactor water level.
 

5) The water decreased to 51 inches thereby resetting the level "8" trip.
 

6) They tried restating the "C" feed water pump...it failed to restart.

7) They started the "A" reactor feed pump.
 

8) The start-up feed regulating valve failed to operate in auto or manual...vessel going down to a RPV level "3".
 

So something buggy was going wrong with the turbine control valve RPS logic, they got a unexpected scram a day later while trouble shooting and testing on the other side for some unknown reason, they lost control of water level, the "C" reactor feed pump wouldn't start for some unknown reason and then the start-up feed regulating valve didn't operate for some unknown reason. There is a lot of gear failing here.

A professional nuclear plant staff aims for no gear or components failing in a scram...it has the opportunity to confusing the licences operators. A professional nuclear plant staff never loses control of the reactor vessel.

I would be surprised if the I&C guys got mixed on the #1 turbine control valve RPS logic and the "B" RPS circuit. In other words, a #1 turbine trip goes on to tripping the "B" RPS side...this 1/B and 2/A wording is very confusing. 

Is this the problem? Agastats and relays not being replaced on a bad test...agastats and relays aging out?

The theme with Palisades and Pilgrim...Entergy having a philosophy of operating their regular and safety equipment to run to failure. Palisades according to the NRC, has a problem with just meeting the minimum intent of the federal rules and this got their plant and their employees in so much trouble. 

Licensee Event Report 50-458 / 2014-003-00

On June 10, 2014, with the plant operating at 100 percent power, technicians performing a scheduled surveillance test found that one instrument channel in the reactor protection system failed its time response acceptance criterion. This was the second of two such tests that failed in similar fashion. Since it is conceivable that the second tested channel was out of specifications at the time the first channel was tested, this condition caused independent redundant channels in the same trip system to be inoperable at the same time. The actions required by the applicable Limiting Condition for Operation were not taken since the operators were not aware of the latent condition at the time of the first surveillance test failure. An engineering evaluation of this condition was performed, and the RPS system was declared operable with compensatory measures. Until this issue is resolved, the frequency of the calibration tests in the channels with Agastat relays has been increased to once per year. This condition is reportable in accordance with 1OCFR50.73(a)(2)(i) (b) as operations prohibited by Technical Specifications, as well as 1OCFR50.73(a)(2)(vii), a potential common-cause inoperability of independent trip channels. Due to the design redundancy of the independent channels of the RPS system, this condition would likely have not prevented the system from performing its safety function. Had an actual full MSIV isolation occurred with the channel response times in their as-found condition, the reactor scram signal would likely have still occurred within the specified instrument response time.
 IMMEDIATE ACTIONS

In the calibrations performed in 2010, a degrading trend in the response times was noted in the four channels containing the Agastat relays (**94**). In the 2010 tests, the response time of each of the four channels was 89 milliseconds. The as-found response times found in the recent tests ranged from 90 to 102 milliseconds. In each case, the Agastat relay was replaced and the response time was then verified to be within specifications. The response times for the channels with no Agastat relays ranged from 41 to 51 milliseconds. 

Here below is another electronic protection device failure. Again two failures in a row in one event. They are not taking care of the plant. First, the huge C feed pump motor shorts and burns, then the closest breaker to the pump (feed water pump breaker) fails to protect the bus by tripping. It is only the next breaker in the line that protects the rest of the plant who trips and works.  

These kinds of failures have been known to catch on fire the whole switchroom...loaded with supplies to other important components. It is a nasty fire in a small area..

Lets get this straight...they were in a start-up with everything new or repaired.

The "C" feedwater was running.

They started the "B"...it shorted. 

The feeder breaker failed...the protection breaker disconnected the whole bus instead of just the shorted main feed pump. As the B and C came from the same bus...the C loss power.

What happened to A feedwater pump, why didn't they start that guy up? Bet you it was tagged out. So all feedwater pumps were unavailable. Hmm,they lost the main condenser and had to shut the main steam isolation valve. You see how this goes on these kinds of accidents, the choice of what system can feed the vessel gets quickly narrowed to almost nothing. They didn't use the A feedwater pump because of losing the Mcond and shutting the MSIVs.

Licensee Event Report 50-458 / 2012-003-00

At the time of the event, the "C" reactor feedwater pump was in service. When the operator started the "B" feedwater pump, an electrical fault occurred at the pump motor. The lockout relay on the pump's feeder breaker failed to trip the breaker, and the main supply breaker to the "B" 13.8kV switchgear tripped to clear the fault. This caused the loss of power to the "C" pump, as well as switchgear supplying the circulating water system and the normal service water system.

The lockout relay installed on the breaker for the "B" feedwater pump is a General Electric HEA 61. The analysis of this event found that the lockout relay failed to operate as designed due to age-related mechanical binding and a possible coil failure. This condition resulted from an inadequate preventative maintenance program for the relays and a design issue with the trip plate.

Basically the vendor was corrupt and incompetent, Entergy had astonishing poor oversite of this vendor maintenance activity. I'll bet you Entergy secretly ok'd the too large lugs.   

The inspection of the terminal box on the "B" feedwater pump determined that fault occurred due to an inadequately crimped terminal lug on one of the three current transformers. The motor (**MO**) had been rewound by a vendor in 2008. When the motor was returned, new lugs were resupplied by the vendor to be installed onsite. The lugs were installed by a local vendor. The investigation found that the lugs were too large for the application. Additionally, the crimping tool used for the installation did not fully compress the lugs, leaving an inadequately bonded connection. 

That is the "run to failure ideology...the coal plants taught them how to do this. It is unbelievable how often they allow these relays and agastates to fail by end of life through an intentionally inadequate preventative maintenance program. Usually the agastates and relays are obsolete and no longer made for the repair parts stream. They get vendors to reverse engineer these obsolete parts and they manufacturer them on their own. Because of this and it is such a inconvenienced to disrupt an outage...they chose to bet the ranch on not failing...close their eyes and wait till one fails.    

The lockout relay installed on the breaker for the "B" feedwater pump is a General Electric HEA 61. The analysis of this event found that the lockout relay failed to operate as designed due to age-related mechanical binding and a possible coil failure. This condition resulted from an inadequate preventative maintenance program for the relays and a design issue with the trip plate.

Oh, the "C" feed pump "failed to start on call" on the current LER starting this off, below (Licensee Event Report 50-458/2011-003-00) the "B" and "C" failed in some manner, in the above the "C" shorted out leading to isolating the whole bus and losing the Mcond and MSIVs. They are really bad with all these feed pump failures in such a short time.
 

Here is the Augmented Inspection below...remember rework problems. What causes rework problems?

RIVER BEND STATION - NRC AUGMENTED INSPECTION TEAM REPORT

05000458/2012009

During a reactor startup on May 24, 2012, operators at River Bend Station initiated a manual scram of the reactor from 33 percent reactor power. The reactor scram was the result of a loss of feedwater, circulating water, and nonsafety-related cooling water caused by an electrical fault associated with a main feedwater pump motor. The fault was not isolated by the motor feeder breaker due to a failed relay, resulting in the trip of the supply breaker for the 13.8 kV nonsafetyrelated electrical bus. Because of a previous cable failure and fire on May 21, 2012, all operating circulating water pumps and nonsafety-related service water pumps were powered through this supply breaker. The loss of the running pumps resulted in the loss of condenser vacuum and cooling water to turbine building and safety-related loads. Both divisions of safetyrelated standby service water started and restored cooling to the safety-related loads.

Licensee Event Report 50-458/2011-003-00

On December 23, 2011, at approximately 6:10 a.m. CST, the main turbine (**TRB**) tripped unexpectedly, resulting in a reactor scram. The plant was stable at 100 percent power at the time of the event, and no safety-related systems were out of service. Operators implemented the appropriate response procedures, and began to stabilize reactor vessel pressure and water level.

The rapid closure of the turbine control valves caused a rise in reactor pressure that actuated at least fifteen of sixteen main steam safety relief valves (SRVs). The initial shrink in reactor water level accompanying the reactor scram caused a Level 3 alarm, with water level reaching a low point of -0.1 inches approximately 15 seconds after the scram (Level 3 is 9.7 inches). The main feedwater control system responded, and the subsequent increase in reactor water level caused a Level 8 trip of all three reactor feedwater pumps (**PMP**) approximately three minutes into the event.

As reactor water level lowered back through the normal operating range, operators attempted to restart a feedwater pump, but component malfunctions were encountered on "B" and "C" pumps. The reactor core isolation cooling (RCIC) (BN) system was manually actuated approximately nine minutes after the scram and injected water into the reactor for approximately two minutes. The "A" feedwater pump was restored to service approximately one minute after RCIC was initiated.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the automatic actuation of the reactor protection system (RPS) (JC).

In the immediate notification performed in accordance with 10 CFR 50.72, it was reported that the reactor vessel Level 3 condition caused the actuation of primary containment isolation valves in the suppression pool cooling system. Those valves were already closed at the time of this event due to the system being out of service.

Here below(Licensee Event Report 50-458/2011-003-00) is what caused the turbine trip below...more vendor incompetence and extremely poor oversight by energy. The theory goes, the philosophy is to reduced the expensive full time educated and experienced River Bend employees...use the cheaper contractor to replace the highly specialized and skilled Entergy employees. Maybe the petroleum well drilling and platform job are sopping up all the good employees?    

Bottom line, the installation and operation the turbine shaft ground system was repeatedly botched...they observed it not wearing properly and they failed to document this condition. This is what caused the turbine trip.  

This all from the beginning is called rework problems...a job is done and is later discovered the job was botched. A bad plant has a lot of rework problems, the rework can go to 50% to 70% of all jobs. It is extraordinarily wasteful and millions of dollars of value is stolen from the stock price and value. 

Main turbine trip 

The trip signal to the main turbine originated in the electro-hydraulic control (EHC) system, and caused a fast closure of all turbine control valves. Analysis of transient data found that both the primary and back-up turbine speed signals became erratic and indicated an overspeed condition. Within approximately one second, all four turbine control valves were commanded to go fully closed. The RPS system responded to the fast closure signals from the turbine control valves, initiating a reactor scram.

The cause of the turbine trip was a spurious backup over-speed trip. An electrical discharge from the turbine shaft to the vicinity of the EHC turbine speed pickup probes generated electromagnetic pulses that influenced the speed probes, which act on magnetic flux associated with a toothed wheel coupled to the turbine shaft. Over-speed signals in at least 2 out of 3 channels caused a turbine trip signal. The cause of the electrical discharge was due to a failure of the shaft grounding system.

The turbine shaft grounding system was modified in 2004 to add a new brush at the midstandard location (between the high-pressure turbine inboard bearing and the thrust bearing). There are four brushes assigned to the turbine shaft, three of which provide ground protection. The mid-standard brush was removed as part of troubleshooting the turbine trip and it was found to have very little wear for the time in service. An inspection conducted by both internal and external technicians concluded that the brush was not providing protection, given the level of wear observed. The brush is designed to pivot with bristle wear to maintain shaft contact. Since less wear was observed than expected, it is concluded the brush wore until the maximum range of the brush pivot was achieved, after which the brush lost contact with the shaft due to making hard contact within the indicator housing.

This investigation also found that the mounting bracket for that brush was improperly fabricated, such that the angle between the brush head and the shaft was not correct. Following this forced outage, the as-left reading on the brush wear indicator is about halfway between "replace" and "new." This allows adequate brush movement and shaft contact. Actions will be taken in the next refueling outage to correct the angle on this bracket to make it read accurately. 

There were significant contributing factors in this event:

• The grounding brush at turbine bearing no. 2 was installed as part of a modification to add a new grounding point. At that time, the preventative maintenance (PM) task for measurement of shaft voltage should have been revised to include shaft voltage measurements from either the new grounding brush or the shaft voltage monitoring. The PM was not revised. Increased shaft voltage would indicate that the shaft grounding brush was not working properly.

• The post-modification testing following installation of the new brush in 2004 was not performed properly. An improperly fabricated mounting bracket built for that modification apparently does not allow the wear indicator to accurately show the "new" indication for a new brush head.

• Maintenance and Engineering personnel recognized that the wear indicator did not accurately measure actual brush wear, but did not document the deficiency in the corrective action program.

The limit switches were out of adjustment with the failure to start the "C" feed pump...a classic rework issue. The botched limit switch job and then retesting cause the main feed pump not to start. A plant has hundreds of thousands to millions of components and relays...if they had a big problem with rework problems it could cause a lot of issue in the control room with degraded and broken components showing up in accidents or scrams. A professional plant staff bets their careers that all components operated as designed.
Remember the staff of a nuclear plant consist of 800 to a 1000 employees. They have a army of willing and high paid contractors and vendors....there really is no excuse here. It is usually plant staff and management disorganization that causes this. It is institutional disorder on a huge level.     

The operator first attempted to start the "C" feedwater pump. Part of the start sequence is the opening of the minimum flow valve, initiated by depressing the pump "start" button. When the pump start sequence was initiated, the operator observed the indication for the minimum flow valve start to travel from closed position to an intermediate position, instead of going fully open. The pump start circuitry is electrically interlocked with that valve position indication, so this failure prevented the pump from starting. Troubleshooting found that the valve was actually opening as commanded, but the limit switches were out of adjustment, preventing the fully open indication from being applied to the start circuitry.

Testing should have picked that up...not discovered in a troublesome scram or accident. You going to discover one day a accident that scares the pants off the staff and public...finding these kinds of problem in just a scram means you will find a very uncomfortably amount of degraded and broken components in a bad accident. It could end in it being more than just a embarrassment to the staff and management...the public and politicians just may lose faith in you.  

The operator then attempted to start the "B" feedwater pump. One of the actions involved in starting a feedwater pump is to verify that the auxiliary lubricating oil pumps on the pump and the gearbox are operating correctly. Upon initiation of the pump start, the operator observed that the gearbox auxiliary oil pump was cycling "on" then "off," which is abnormal. Troubleshooting found that a pressure regulator in that lube oil system was out of adjustment. This issue was corrected prior to plant restart.

This is interesting because it implicates the turbine grounding system and brushes...static electricity builds up and discharge across the HP turbine

My professional opinion is the turbine and the turbine control system is junk. You had a lot trips over this. It needs to be completely refurbished or replaced. Who does the contractor servicing of your turbine?  

Automatic Reactor Scram During Main Turbine Control Valve Testing Due to Control System Malfunction

Of great note:

Final Precursor Analysis Sequence Precursor Program -- Office of Nuclear Regulatory Research

River Bend Station Automatic Reactor Trip Due to Loss of Non-Vital 120V Instrument Bus

Event Date 12/10/2004 LER: 458/04-005-01 CCDP1 =2.7 x 10-5

May 16, 2006

This is a example with Entergy-River Bend again having a serous transient and scram based on a preventable fault on their transmission system. We see again lots of equipment failures leading to confusing the operators in the very  busy portion of dealing with the scram.

Particular here in the special inspection, the NRC has implicated River Bend with seriously mismanaging vessel level control...banging level up and down all over the place...mis-communication with coordinating operating the safety relief valve and managing the vessel control.  Basically simulator training is poor with managing reactor vessel level control and they have big troubles with simulator fidelity issues in modeling the vessel swell in a scram and the operation SRVs. They were training all the operators on a simulator model on the behavior of vessel level that didn't match what vessel level actually did in a scram. 

Again and again, why does River Bend have so many broken components creating scrams, then once in a scram, why are there so many more broken components showing up and what about all the human errors?

At least a Feed pump didn't burn up or fail upon call. That seems to happen much later.  

You can size up how competent a nuclear plant crew is and how effective simulator training is by how they manage vessel water. If is bangs around past high level trips and whips down to below the low vessel level trips...it means these guys are poorly trained and the crews  won't be effective in a riskfull accident. It is a indicator of safety culture. It test crew coordination and communication...this is a prerequisite for safety. 

If a regulator allows the crew to bang around nuclear vessel level over and over...level mis-management...then this is a indication of the ineffectiveness of a regulator to control and limit chaos in the control room of a nuclear power plant. 

Now if the NRC has control room criticism like in the below inspection report about inadequate vessel level management, then the site in a few years have another vessel level management problem of bigger proportion, has a continuing problem with vessel level management...then this in on the NRC. The agency isn't carefully observing crew vessel level management especially in the simulator for a prolonged period of time. The agency and the ROP lacks the stamina and the attention in detail to ascertain all the crews are competent in managing vessel control after finding a initial serous shortcoming in vessel level management.

March 2007 IR: (banging around uncontrollably vessel water level); "The team reviewed plant operating parameters and the associated time line elements and determined that reactor vessel water level had gone outside the established level band at least 6 times during the 53 minutes that the main steam isolation valves were closed."

This is what you call a NRC institutional breakdown or failure. The agency aren't self monitoring their actions or violations of the licensees...keeping tabs of the ROP and NRC bureaucratic structure to see if it creates a positive change in the licensee.

If the agency interaction with a licensee doesn't cause deep and positive long term behaviors and drive positive vessel level management changes in a licensee on the first swipe...if the agency isn't self aware of the effectiveness of their interactions, then they aren't in control of a bad actor licensee. Their ROP isn't effective on what we all want out of the nuclear power industry.             

First swipe at trying to fix vessel level management: February 10, 2005: SUBJECT: RIVER BEND STATION - SPECIAL INSPECTION REPORT 05000458/2004012

Reactor Coolant System Level 2 Actuation 

At approximately 7:35 a.m., the operators closed the outboard MSIVs due to lowering main condenser vacuum. At 7:58 a.m., the inboard MISVs were closed, also due to lowering main condenser vacuum. This was an anticipatory action taken with at least an 8.5-inch vacuum remaining in the main condenser. Reactor pressure was being controlled by the SRV low-low set function. At 8:04 a.m. level control was assigned to the At The Controls (ATC) operator who was working on restoring feedwater. At 8:10 a.m., SRV F0551D opened on low-low set and the control switch was taken to the OPEN position to bring pressure to the low end of the pressure band; the band was set at 500-1090 psig. At this point, through licensed operator interviews, the inspectors determined that it was not clear who had pressure control or which operator placed the SRV control switch in the OPEN position. The root cause investigation stated that the ATC operator had responsibility for both level and pressure control. This is a difference between the team’s investigation and the licensee’s root cause.

At 8:14 a.m. a Level 3 was reached. The SRV remained open until 8:16 a.m. when the ATC operator reported that the reactor pressure vessel (RPV) level was decreasing and approaching the Level 2 setpoint. An operator was instructed to close the open SRV, while another operator was directed to inject with high pressure core spray. The closure of the SRV promptly dropped level to -52 inches, which exceeded the Level 2 setpoint of -43 inches. The only remaining recirculation pump tripped. Feedwater Pump FWS-P1C was started. Within one minute, RPV level was restored above the Level 2 setpoint and restored above the Level 3 setpoint within 3 minutes. During this time, the CRS was observing the ERIS display for RPV level and did not notice any change because of the power loss to that system.

The Level 2 that was experienced by the operators was not expected, nor should it have occurred. There were at least three contributing causes for the Level 2. First, the ATC operator should not have had responsibility for both level and pressure control. Second, communication between the ATC operator and the SRV operator was not sufficient to limit unexpected RPV level fluctuations. At the time of the incident, all MSIVs were closed and the ATC operator was in the process of restarting a feedwater pump.

According to the RBS's pressure control strategy, pressure should have been controlled via the main steam line drains or through cycling SRVs. If SRV cycling is to be used, then close coordination between the ATC operator and the SRV operator should take place to limit unexpected level fluctuations. Contrary to this, an operator placed the SRV into the OPEN position and walked away from the control board without sufficient coordination with the ATC operator. The third contributing cause was that the CRS relied on the ERIS display that was not functioning properly. The CRS was cognizant that the ERIS system was suspect, but continued to rely on the system output. According to the ERIS display at the time of the Level 2, level was not changing.

...10 CFR 55.46.c states in part, “A plant-referenced simulator used for the administration of the operating test or to meet experience requirements . . . must demonstrate expected plant response to operator input and to normal, transient, and accident conditions to which the simulator has been designed to respond . . . .” RBS experienced two reactor scrams (August 15 and October 1, 2004) in which actual plant SRV manipulations caused shrink, swell, and level indications that were different than what was modeled in the simulator. After some investigation by the licensee, it was determined that level variations in the simulator were 6-8 inches different than in the actual plant. Considering that RPV level is normally maintained between Level 8 (51 inches) and Level 3 (9.7 inches), 6-8 inches constitutes approximately a 15-20 percent difference than actual plant condition. Coupled with the fact that most of the operators on shift during the events had never actually manipulated SRVs in the plant, this simulator fidelity deficiency could have an impact on operator performance. This issue was documented in the licensee’s corrective action program in Condition Report CR-RBS-2004-2334. This violation is of very low safety significance because it did not involve an exam or operating test, but did involve a simulator fidelity issue which impacted operator actions and resulted in...

Second swipe: March 1, 2007 SUBJECT: RIVER BEND STATION - NRC SPECIAL INSPECTION REPORT 05000458/2006013

3.1.3 Safety/Relief Valve Operation Discussion: On October 19, 2006, at about 5:59 pm, an inadvertent main steam isolation occurred on low reactor pressure caused by high pressure core spray injection. With the main steam isolation valves closed, reactor pressure began to increase as the large volume of cooler water injected by the high pressure core spray system expanded. Approximately 7 minutes later, with reactor pressure at 1090 psig, operators opened a safety/relief valve to control pressure below the automatic relief setpoint. The Table 3.1-2 documents the valve manipulations that occurred during the event. 

Abnormal Operating Procedure AOP-0001, OSP-0053, Attachment 1B, "Post Scram Pressure Control Strategies," Revision 5, states, in part,

"1.2 Post-Scram Pressure Control for an MSIV Isolation.

     "1.2.1 IF only the inboard MSIVs close due to a loss             of air to containment, THEN perform the                   following:

    "1. Take manual control of the inboard MSIVs by             taking the control switch of each valve to             CLOSE.

    "2. Utilize available steam drains to control               pressure.

    "3. IF required, THEN augment pressure control with         SRVs. Each SRV cycle should beclosely           coordinated with the at-the-controls operator.

    "1.2.2. For a full MSIV isolation, perform the                       following:

    "1. Verify SRVs are cycling automatically to                control pressure.

    "2. IF automatic SRV cycling is preventing the             level control operator from controlling RPV             water level in the required band, THEN perform         one of the following:

• Closely coordinate with the level control operator to manually operate SRVs as required to control pressure in the prescribe pressure band, without driving level outside the prescribed level band.

• Transition level control from the Feed and Condensate system to the RCIC system.

• Run RCIC either directly for level control, or in pressure control lineup (maximized)."

However, following the main steam line isolation, the safety/relief valves never operated in automatic. Therefore, operators did not verify that they were cycling in automatic, nor could they observe that the automatic function was preventing the level-control operator from controlling reactor pressure vessel level in the required band. In addition, manual control of the safety/relief valves drove level out of the required band on multiple occasions during the event. Licensed operators and plant management stated that operators knew that under the conditions that existed they could not properly control level if the safety/relief valves were cycling in automatic and that they had been trained to operate the safety/relief valves manually under these conditions. This expectation was supported by operations management. Additionally, plant management stated that this procedure was not a requirement and was in conflict with the bases of the emergency operating procedures. The team reviewed Section 1, “Purpose,” of Attachment 1B and noted that Step 1.3 stated:

“The “Continuous Use” designation of this procedure is intended to apply to the Hard Card attachments only. The Strategy attachments and procedure body are informational in nature and do not provide step by step procedural guidance.

Section 3, “Strategies,” Step 1.3, stated:

“Strategy attachments are provided in this procedure for those activities which do not lend themselves to step by step instructions due to the varying impact on these activities by differing plant conditions for different transients.”

Additionally, in Section 4, “Hard Cards,” Step 4.7.1 stated:

“Attachments 1A, 1B, and 1C are strategies, not Hard Cards.”

The team noted that these procedure statements should be reviewed in light of the definitions given in River Bend Nuclear Procedure RBNP-001, Revision 25, “Control and Use of RBS Procedures.” Section 3, “Definitions,” Step 3.4 defines the level of use of plant procedures, indicating that there are three categories of procedure: Continuous Use, Reference Use, and Informational Use.”

Informational use procedures were defined as procedures frequently performed or not complex in which the activity could be accomplished from memory and within the skill of qualified individuals. While these procedures are not required to be available at the work location, they are still expected to be followed. The team also reviewed the bases for EOP-0001, Step R P-3, “Stabilize RPV Pressure Below 1090 psig.” One portion of this document suggested that Safety/relief valves should generally be opened manually. However, the bases discussed many exceptions to this general statement. Additionally, the document stated:

“. . .the adequacy of steps taken to stabilize RPV pressure must be judged by the effect of any continuing pressure variations on RPV water level. . . “

The team reviewed plant operating parameters and the associated time line elements and determined that reactor vessel water level had gone outside the established level band at least 6 times during the 53 minutes that the main steam isolation valves were closed. This fact, combined with an evaluation of the data, shown in Table 3.1-2 indicated to the team that operators may have been attempting to control pressure at specific points without regard for reactor water level at the time. The team concluded that the failure of licensed operators to permit the safety/relief valves to cycle in automatic and to manually operate Safety/relief valves without driving level outside the prescribed level band, as required by abnormal operating procedures, was a violation.

Bottom line, from the 2007 vessel management problem till right up to today, River Bend has has unabated serious and poor vessel water level management issues uncontrolled by the

Jessie Roberson: New Republican NRC Commissioner Nominee

Just incompetent musical chairs between US boards and commissions. I think Jessie will be at the beck and call of the nuclear industry and US commissions...

Dive Insight:

Roberson is an ex-Bush official at the Department of Energy, but she currently serves as vice chairman of the Defense Nuclear Facilities Safety Board – a position Obama appointed her to a year ago, following years of service after being initially nominated by President Bill Clinton.
More significant than her nominatio itself may be that the NRC will finally have its full slate of five regulators, following significant turnover at in recent years. 

According to the DNFSB, Roberson has more than three decades of experience in the industry, “with profound experience in low level waste management, environmental restoration, reactor operations and project management.” Prior to working at the Department of Energy, Roberson worked at Georgia Power as a system engineering specialist in the late 80s. 

I don't like her. She seems to be moving around a lot.

I fault her with not making her troops dig deeper and pick up the decline of the Wasted Isolate Project Plant(WIPP)...see the organization breakdown and correct it before the contamination event and the one billion dollar waste of governmental monies over the incident. Along with Las Alamos who improperly filled the drums.

She has had her turn at detecting government failures and fixing them before they got big....why reward personal incompetence.

Honestly, is she competent:

Defense Nuclear Facilities Safety Board:

Improvements Needed to Strengthen Internal Control and Promote Transparency [Reissued on March 2, 2015]

GAO-15-181: Published: Jan 20, 2015. Publicly Released: Feb 19, 2015. 

ASSESSMENT OF THE DEFENSE NUCLEAR FACILITIES SAFETY BOARD WORKFORCE AND CULTURE

Is she just going to do nothing ride the governmental oversight  wave in the NRC like of WIPPS

Because she is black in a all white and male organization...is she going to be afraid to move her weight and influence around in order to serve the higher interest of the nation just like Obama.  In the lead up to the WIPPS, the DNFSB "BOARD" was horribly politically dysfunctional with infighting, just like the NRC in the last few years. What does she got to bring to the NRC commission table except a pretty face.

Maybe that is what the republicans want, another weak and do nothing commissioner and NRC???

Jessie Roberson, Nominee for Commissioner, Nuclear Regulatory Commission

Jessie Roberson is Vice Chairman and Member of the Defense Nuclear Facilities Safety Board (DNFSB), positions she has held since 2010.  In 2009, Ms. Roberson was the Senior Vice President for Environmental Affairs at Safe Harbor Energy.  Prior to that, she was an environmental consultant for Innovative Solutions from 2007 to 2009.  From 2006 to 2007, Ms. Roberson served as the President of the Nuclear Services Division at CH2M Hill.  Before that role, she served as the Director of Nuclear Regulatory Programs at Exelon Corporation from 2004 to 2006.  From 2001 to 2004, Ms. Roberson served as Assistant Secretary for Environmental Management at the Department of Energy.  She previously served as a member of the DNFSB from 2000 to 2001.  Ms. Roberson served at the Department of Energy as a Site Manager for the Rocky Flats Environmental Technology Site from 1994 to 2000 and as a Waste Management and Environmental Deputy Assistant Manager for the Savannah River Plant from 1989 to 1994.  Ms. Roberson worked for Georgia Power Company as a Senior Systems Electrical Engineer from 1987 to 1989.  Earlier in her career, she was a Nuclear Operations Manager at the Savannah River Plant for E.I. DuPont from 1981 to 1987.  Ms. Roberson received a B.S. from the University of Tennessee.

Defense Nuclear Facilities Safety Board

Our Board Members

Ms. Jessie Hill Roberson a native of Evergreen, Alabama, has over 30 years of experience in the nuclear engineering field, with profound experience in low level waste management, environmental restoration, reactor operations and project management. Ms. Roberson’s who is currently serving her second tour with the Defense Nuclear Facility Safety Board (DNFSB) was initially nominated as a member of the Board in September 1999 by President Bill Clinton. Ms. Roberson was confirmed by the United States Senate in January 2000. After a short departure from the board, Ms. Roberson was again nominated as Vice Chairman of the Board by President Barack Obama. Ms. Roberson is currently the acting Chairman.

The Battle for Safety at Pilgrim Nuclear Plant (secret cell phone recording of NRC officials)

Yesterday I was listening in on the NRC’s meeting with Pilgrim plant concerning their SRVs on my cell phone At the end of the meeting I trying to wake up my cell phone, trying to prepare for the beginning of the public comment part of the meeting. I dropped the phone call and had to call back. I was shocked to learn there was no other people willing to make a comment or ask a questions to the NRC when I called right back. By the time I called back, the meeting had ended. I made notes for discussion with the NRC officials for the public part of the meeting. Generally the NRC will just let me give my spiel, they won’t openly discuss the issues with me. I immediately called the meeting contact person Mr. McKinley thinking he would schedule a phone discussion over the SRVs later. I thought I was just leaving a voice recording on his phone. He answered my call and immediately wanted to discuss my issues. I have on phone recording app on my cell phone for years…I record automatically every phone call on my cell phone.

Basically I feel the NRC employees and especially the agency's operating plant staff are extraordinarily people...but bad national policy is inhibiting the employees from driving dangerous chaos out of the national fleet. They are a captured agency. 

This might be a big deal if a big and embarrassing nuclear event occurs in the industry within the next few years, especially concerning Pilgrim.  

Technically recording the phone call without getting consent is illegal…especially if it is a government official.  I certainly risk being taken to court over this or my special access to the NRC is going to come end. I thinks this discussions reflect very well on these employees and the NRC in the whole.
 

Private cell phone recording of Mr. McKinley Chief, Division of Reactor Projects, Branch 5 and Mike Mulligan concerning Pilgrim SRV meeting.

From McKinley, Raymond 

To steamshovel2002@yahoo.com 

Thu, Jul 9, 2015 11:59 AM EDT 

Mike,
Thank you for listening in on the enforcement conference and providing your insights yesterday evening. You asked a question about how the LOOP initiating event frequency factored into the risk analysis and if that initiating event frequency is ever updated. I reached out to one of our Senior Risk Analysts, and I think I can better address that question. If you have some time, I can give you a call or you can call me. We can set up a time today or on Monday to discuss further. Let me know if you are available.
Thanks,
Ray McKinley Chief, Division of Reactor Projects, Branch 5 U.S. NRC Region 610-337-5150

Private cell phone recording between, Christopher Cahill Senior Reactor Analysis, Chief McKinley and Mike Mulligan 

We discussed this below 2.206 in 2013...I read this below italicized paragraph to Mr McKinley. I clearly stated the date. The NRC

2.206: "The repeated nature of the failure of the safety relief valves means Entergy doesn't know the mechanism of the failure.. .it is a common mode failure. The design and manufacture of these valves are defective and it is extremely unsafe to operate a nuclear plant with all safety relief valves being INOP. A condition adverse to quality..." 

discovered during the 2015 inspection Entergy had failed to disclose a SRV failed to operate in the 2013 blizzard LOOP. I believe Entergy "not disclosing" this on their own in 2013 should have led to a red finding whether from sloppiness or an intentional falsification. I didn't like Mr. Kckinley's response to me. I won't get confrontational to him in this setting, after all I need to respect he is a high US governmental official. He said nobody in Entergy or the NRC knew at the 2013 time frame the SRV's were defective or should be considered a common mode failure. Everyone realizes my below italicized is a true statement today. How come I knew in 2013 these valves were defectives valves and Entergy and the NRC didn't didn't...I had the information in their document system. Remember energy yanked out the three stage SRVs in the spring 2015 outage because they were unsafe. They are a defective design.

Further, the NRC was negligent with knowingly allowing Pilgrim to start-up with these defective components, allowed Pilgrim to get into the next outage just a month or two away. Months later in the 2015 outage the NRC mysteriously discovered the failure of the SRV to operate, Pilgrim burying this in their documents and not reporting it to the agency. This SRV failure to operate discovered by the NRC forced Pilgrim to remove the defective 3 stage and replace it with the 2 stage. This whole vendor dragging their feet on the SRV investigation and the incompetence of pilgrim supporting the operational period between the 2015 blizzard and the outage stinks with allowing the plant to operate with bad valves for convenience. Basically dragging your feet on investigations and false reporting to the NRC pays off allowing pilgrim to get to the outage. They replaced the unsafe valves in the outage. I contend these valves were unsafe before they put them in the plant and entergy and the NRC should have known it.

If the agency post blizzard 2015, and even in Blizzard 2013, if the agency did a complete and competent investigation of the undying material facts of the SRVs, they would have discovered in the available information and documentation, certainly post 2015 blizzard, those SRVs were dangerous. If the NRC would have uncovered all the facts and the available evidence, the agency would have force Pilgrim to replace those SRVs before state-up.

There is nothing but mostly licensee and NRC not challengable assumptions behind all of this including the violation level. They play these games in the dark and they have nothing to be afraid of.       

As these officials told me, the complexity of poor design of these valves and the degradation mechanism...the situation is too complex to model. The NRC was forced to go outside their risk modeling and basically depend on the skill of the craft to come up to a violation level.

It is extraordinarily simplistic and constitutes a falsification, everyone using just two valve failures as keying a violation level. You see the dangerousness what they are setting up, it is the best view of information they selective chose to show the public. It is not the full story. It is nothing but a pyramid scheme based on not public information...you seeing a false facade they are projecting to you.

We are talking about high government expert officials...to explain to me how they came up with the violation level. The first official called in the region I risk specialist, then the second official needed or wanted to call in laboratory to complete the discussion surrounding the violation level and the LOOP frequency. It is so complex, they need to keep calling these experts with a higher education, it becomes a bottomless black hole with never an answer to your question.               

2.206: Request Emergency shutdown of Pilgrim surrounding their SRVs 

March 7, 2013:

"The repeated nature of the failure of the safety relief valves means Entergy doesn't know the mechanism of the failure.. .it is a common mode failure. The design and manufacture of these valves are defective and it is extremely unsafe to operate a nuclear plant with all safety relief valves being INOP. A condition adverse to quality..."    

Request:  

1) Request an immediate shutdown the Pilgrim Plant.

2) This is the second time I requested a special NRC inspection concerning the defective SRV valves.

3) Not allow the plant to restart Pilgrim until they fully understand the past failure mechanisms of the four bad new three stage safety relief valves.

4) Request the OIG investigate this cover-up to keep an unsafe nuclear plant at power.

NTSB Urges Cameras For Amtrak Nuclear Power Plants

Why do you think the US public has never seen a actually plant trip or accident through a video recording? 

But of the extraordinarily protectiveness of the NRC protecting the nuclear industry...not mandating recorders in the control room. 

NTSB urges cameras for Amtrak trains 

The National Transportation Safety Board on Wednesday urged Amtrak to install "crash- and fire-protected inward- and outward-facing audio and image recorders" on all locomotives.  

The recommendation came in response to the May 12 derailment of Amtrak Train 188 in Port Richmond that killed eight passengers and injured 200. 

Amtrak CEO Joseph Boardman said last month that Amtrak would install inward-facing video cameras in all of its 300 locomotives, starting with 70 Siemens locomotives now being put into service on the Northeast Corridor. 

Amtrak trains already have outward-facing cameras.
The NTSB, which has been pushing for cameras for years, said it was encouraged by Amtrak's actions, "but believes that additional requirements for a complete inward- and outward-facing audio and image recorder system are necessary." 

The NTSB also asked for semiannual public progress reports on installing the recorders, since Boardman did not specify how soon they would be in place. 

Such recorders would assist crash investigators and help Amtrak supervisors determine if crew members are following operating rules, the NTSB said in a letter sent Wednesday to Boardman by NTSB Chairman Christopher Hart. 

The union that represents Amtrak engineers, the Brotherhood of Locomotive Engineers and Trainmen, has opposed the cameras as an invasion of privacy. 

Union officials did not respond Wednesday to a reporter's requests for comment on the NTSB recommendation. 

Last month, Dennis Pierce, president of the Brotherhood of Locomotive Engineers and Trainmen, told a House committee that "installation of cameras will provide the public nothing more than a false sense of security."  

"These cameras are an accident-investigation tool and not an accident-prevention tool," Pierce said. "Not a single life would have been saved if the locomotive cab on Amtrak 188 had been equipped with an inward-facing camera." 

Amtrak spokesman Craig Schulz said, "Amtrak is reviewing the NTSB recommendations and will incorporate them, as appropriate, into our plan to install inward-facing cameras in the locomotive fleet."

Indian Point 3 Confusion

Now it makes sense... IP3 returns to service BUCHANAN – The Indian Point nuclear power plant Unit 3 returned to service on Thursday afternoon after it was manually shut down on Wednesday when control room operators observed fluctuating water levels inside a steam generator. Operators determined that one of the unit’s three condensate pumps, which is part of the system that feeds water into the plant’s steam generators, automatically shut down while the unit was operating at full power, causing water levels inside the steam generator to fluctuate. The three condensate pumps are located on the non-nuclear side of the plant. The unit is operating safely on two condensate pumps while engineers and mechanics repair the third. Unit 2 continues to operate at full power. Entergy spokesman Jerry Nappi said earlier Thursday that workers were making repairs to one of the water pumps that shut down the reactor, which was expected to return to service by Saturday.

I wonder why this newspaper got it wrong...Entergy feeding them bum information? 

Wednesday's shutdown was the latest incident at the power plant over the last few months. 

Downed Indian Point reactor due back online 

A tanker goes past Indian Point on May 11, two days after a transformer explosion released oil into the Hudson River.(Photo: Ricky Flores/The Journal News)Buy Photo
BUCHANAN – Entergy expects its down Indian Point nuclear reactor to start pumping out electricity again by the week's end, a spokesman said Thursday. 

"They are making repairs to one of the water pumps that shut down Unit 3," Entergy spokesman Jerry Nappi said. "We expect the plant to be back up by the end of the week." It should be running by Saturday, he said. 

A malfunctioning water pump forced operators to shut down the Unit 3 nuclear reactor at about 2:30 p.m. Wednesday. The plant's second reactor - Unit 2 - continues to operate at full capacity...

The 1% indicates they tried to startup...now they are talking about the end of the week end. Something doesn't add up? 

Power Status

Unit	Power
Beaver Valley 1	100
Beaver Valley 2	100
Calvert Cliffs 1	100
Calvert Cliffs 2	100
FitzPatrick	100
Ginna	100
Hope Creek 1	100
Indian Point 2	100
**********Indian Point 3	1
Limerick 1	100
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
Peach Bottom 3	100
Pilgrim 1	100
Salem 1	100
Salem 2	100
Seabrook 1	100
Susquehanna 1	100
Susquehanna 2	100
Three Mile Island 1	100

The Future According to Deminion

It is the best option according to the rules...not what is best to the locale.

The moral of this story they want the utilities to borrow money or go into the bond market…they’d prefer the equipment you buy don’t work. They just want you to borrow and borrow and borrow with no need to do good. 

Dominion outlines new power plan

Three of the plans would result in retirements of coal capacity, including units three and four of the Chesterfield Power Station, the utility’s largest coal-fired generating plant, along with two more in Mecklenburg County and one in York County.

• The cheapest alternative involves adding 4,000 megawatts of utility-scale solar, which would require land space almost as large as the city of Richmond and cost an additional $4.3 billion. The plan also calls for additional natural gas generation as a backup for peak periods, since solar energy isn’t always reliable and currently can’t be stored.

• Converting coal plants to use natural gas for one-quarter of their electricity production (co-firing plants) while also ramping up solar and natural gas would cost about $5 billion more but would increase even further the company’s reliance on natural gas.

• Adding a third nuclear reactor at the North Anna plant in Louisa County would reduce carbon emissions more than any other option, but at $7.2 billion it would cost about 67 percent more than the solar option

• Focusing on offshore wind would cost $15.3 billion, a price that all but takes that plan off the table unless Dominion can find a way to reduce costs. The company recently delayed plans to install offshore turbines as a test case when the price was nearly double the company’s $230 million estimate.

Dominion weighs each of the options based on growing demand and reliability as well as cost.

“Utility-scale solar looks very good to us. It’s the lowest-cost deal, but there’s a lot of analysis to be done, so it’s not a done deal yet,” Wohlfarth said.

Environmental groups have called on Dominion to rely on renewable energy such as solar and wind power to meet the growth in demand, which is expected to be about 1.5 percent per year.

“If Dominion were looking out for the best interests of Virginians, it would prioritize aggressive investments in solar, energy efficiency and offshore wind and stop doubling down on dirty fracked

gas,” said Mike Tidwell, director for the Chesapeake Climate Action Network.

Mike Mulligan’s National Nuclear Plant Decommissioning Plan

Let’s say Vermont Yankee has $600 million dollars in their decommission fund.

We set up a national nuclear plant decommissioning agency. It could be in the NRC or DOE.  They would be tasked with decommissioning a plant within 10 years and returning the property into a mostly green field. There would be tremendous efficiencies with a centralized single organization running the show national wide. You could have a rock solid government core employee base with the best education and skills base (the best of what a centralized and hierarchal  organization can do for you) to decommission the plants or contracting it out. The power of government could enforce the cost and quality of decommissioning...the power of governmental mandated transparency would insure safety and mandated public and community participation. We just get the corporation sticking their middle fingers at everyone right now. It would be really inefficient to do it corporation by corporation or plant by plant.

You’d be making a negotiation and then a contract with the owners to take over the decommissioning fund and then complete decommissioning. It would be in agreement  with who then owns the property. So you would negotiate with Entergy saying the NRC/DOE would take over the complete decommissioning of VY if you throw in another $100 million dollars ($600 plus another $100) or something. I am sure Entergy would jump at the chance with getting rid of this stinking dead dog.

The excess cost you’d grab by putting excess decommissioning cost in the national tax base.  I am sure this would be just a matter of a few dollars for each of our corporate and individual taxes.  It would be a win win for these nuclear corporations and it would professionally put quickly to bed these decommissioned nuclear plants. We would have a national standard on the time a plant sits in the decommissioning and it would be set by government

I hope a deal like this would be the beginning of an interim fuel storage area and then onto a permanent storage.  

This then will give the nuclear utilities the option if their plants were financially hanging on by a thread and collectively a burden to the corporation, they would just dump the dinosaur into permanent  shutdown and the decommissioning negotiations with the national decommissioning agency. It would make the offending hulk of plant dinosaur disappear from their corporate books. They could focus their assets and resources with running and maintaining the remaining plants.  

Dumping the dying dinosaur plants into decommissioning would create an incentive to go into green energy and dump the oldest and financially most shaky nuclear plants into permanent shutdown. Maybe even prepare for the new nuclear plant rebuild.  It could head off disgracing the NRC and the owners in a financial large nuclear plant mishap or even head off a nuclear plant meltdown in the most probable nuclear plants.  You could consolidate the NRC  and nuclear plant employees into a smaller number of plants making everyone operate better and safer.   

This is just a general draft of a plan or idea. What would you have as a solution or plan for this growing problem. We got to deal with these problems. There will never be a pure ideological fix.       

Brattleboro Reformer Is On Artificial Respiration and Brain Dead

I don't think the" Commons" is diversified enough to pick up the slack. More low pay and crap volunteerism.

They get what they deserve...

Digger

Brattleboro Reformer, Bennington Banner, Manchester Journal lay off editorial staff

New England Newspapers Inc., has laid off 10 editorial employees in Vermont and Massachusetts.

 Five newsroom employees in Vermont were handed pink slips on Friday.

No formal announcement has been made by the newspaper chain, which includes the Brattleboro Reformer, the Bennington Banner, the Manchester Journal and the Berkshire Eagle in Pittsfield, Massachusetts.

The company laid off three newsroom staffers at the Reformer. Tom D’Errico, the manager of content marketing, Mike Faher, senior reporter, and Pat Smith, the newsroom clerk, were given notice on Friday. On June 12, Michelle Karas, the managing editor of the Reformer and the Banner left earlier to take a job at The Colorado Springs Gazette. The Banner laid off newly hired reporter Jacob Colone, and the Journal let go of Brandon Canevari.

That leaves skeleton crews at all three newspapers. Andrew McKeever, the editor of the Journal, has no reporter on staff. There will be just two reporters at the Reformer, Dominic Poli and Howard Weiss-Tisman, as reporter Chris Mays has been dispatched to the Banner where he will work with Keith Whitcomb and Derek Carson.

Kevin Moran, the regional vice president of the New England Newspapers, was not immediately available for comment.

The Reformer building is listed for sale.

New England Newspapers is part of the troubled Digital First Media newspaper chain, which owns newspapers in 15 states, including The Denver Post, the Los Angeles Daily News, the San Jose Mercury News, New Haven Register and the St. Paul Pioneer Press.

Apollo Global Management, a hedge fund, was poised to purchase the company in the spring, but backed out. Not long after, John Paton, the CEO of DFM, stepped down, according to Jim Romensko, a newspaper industry reporter. In recent weeks, Digital First sold off properties in New Mexico and Texas to Gannett, according to the Poynter Institute blog. 

On Friday, The Saratogian and the Troy Reporter in New York announced layoffs and voluntary buyouts for 11 editorial staffers.

Indian Point is Turning Into Junk

Pretty pathetic excuses the failed paper insulation  and the faulty valves. How come, asking coming from such a expensive and invaluable reliability piece of gear, why was it paper?

I could make the case the intense activity forcing Entergy to spend money on Pilgrim, Fitz and Indian Point is diluting the resources from Entergy's Region IV plants. 

These are closely related components: why isn't this indicative of the maintenance and reliability quality problems plant wide. The idea of two problem and especially closely related components jumping out failing in one event is very worrisome. There are over 5 million parts in one plant, and this is a aging obsolete two plant facility... only a teeny percentage of component going bad can wrought terrible trouble to a plant and a fleet of plants. I think this site is getting insufficient maintenance funding just like Pilgrim, River Bend, Grand Gulf  and Waterford. Entergy is in trouble!!!

• Entergy, the nuclear plant's operator, announced Tuesday the failed insulation — made of special paper — caused a short circuit in a high-voltage coil.

• The company concluded that some sprinkler valves malfunctioned and didn't automatically close as designed. 

Faulty insulation caused Indian Point fire, oil spill
Ernie Garcia, elgarcia@lohud.com 5:02 p.m. EDT June 30, 2015The company regularly inspects its insulation for signs of degradation, but no problems were seen before the fire.

A tanker goes past Indian Point on May 11, two days after a transformer explosion released oil into the Hudson River.(Photo: Ricky Flores/The Journal News)Buy PhotoStory Highlights

• About 3,000 gallons of transformer oil spilled into the Hudson River

• Transformer oil is similar to mineral oil or baby oil

An insulation failure in a transformer caused the May 9 fire at the Indian Point Energy Center that spilled about 3,000 gallons of oil in the Hudson River. 

Entergy, the nuclear plant's operator, announced Tuesday the failed insulation — made of special paper — caused a short circuit in a high-voltage coil. The company regularly inspects its paper insulation for signs of degradation, but no problems were detected before the fire near the Unit 3 generator. 

No radiation was released during the fire and the generator automatically shut down as designed; it resumed service May 25. Entergy said it will continue its analysis of the paper insulation. 

"We have been working closely with independent engineers, and with federal and state agencies, to address issues surrounding the May 9 transformer failure, and corrective actions are well under way," said Bill Mohl, president of Entergy Wholesale Commodities, the Entergy business unit that owns Indian Point. 

"These actions reinforce our commitment to environmental responsibility and transparency, as well as the continued safe, secure and reliable operation of Indian Point," he added. 

The transformer contained 24,300 gallons of dielectric fluid, a clear mineral oil that serves as a cooling agent and insulation. About 8,300 gallons of oil have been recovered from the moat beneath the transformer, inside the transformer, drains and areas around the transformer yard, or were burned in the fire. 

Contractors are investigating the transformer yard and other areas on site to see if more transformer oil can be recovered and prevent any potential migration. Six shoreline locations required environmental cleaning, which was completed June 5. 

In another investigation related to the fire, Entergy staffers looked at why water from fire sprinklers accumulated in a building that contains electrical equipment powering some of the plant's safety systems. The company concluded that some sprinkler valves malfunctioned and didn't automatically close as designed. 

None of the electrical systems were damaged by the water. Entergy is modifying its preventive maintenance and testing to ensure the sprinkler valves operate properly.
The U.S. Nuclear Regulatory Commission began a special inspection of Indian Point related to the accumulated water on May 19. That inquiry continues.