Massive Warming In NE Continental Shelf: Implication For Coastal Nuclear Plants?

June 26

The Atlantic 'conveyor belt' and climate: 10 years of the RAPID project

The question is, how often will the wind be coming in the Northeast direction...

Dangerous jellyfish appearing at Jersey shore – News

June 23, 2015 at 9:24 pm

It’s not what Harvey Cedars Beach Patrol Captain Randy Townsend usually sees on the resort’s beaches: a risky jellyfish-like creature called a Portuguese man o’war. “When the wind is coming from the northeast, warm water from the Gulf Stream comes to shore”, the post read. According to National Geographic, it moves by floating on the water’s surface, drifting on the currents, catching the wind.

 

June 16

Why can't the main stream media help us understand these interactions? I bet they will say not enough people interested in it. 

The Atlantic Ocean's Cool Phase Will Change The World's Weather

By The Conversation  

May 29th 2015 11:30 AM 

The Atlantic Ocean’s surface temperature swings between warm and cold phases every few decades. Like its higher-frequency Pacific relative El Nino, this so-called “Atlantic Multidecadal Oscillation” can alter weather patterns throughout the world.

The warmer spell we’ve seen since the late 1990s has generally meant warmer conditions in Ireland and Britain, more North Atlantic hurricanes, and worse droughts in the US Midwest.

However a colder phase in the Atlantic could bring drought and consequent famine to the developing countries of Africa’s Sahel region. In the UK it would offer a brief respite from the rise of global temperatures, while less rainfall would mean more frequent summer barbecues. A cold Atlantic also means fewer hurricanes hitting the southern US.

The good news is our latest research, published in the journal Nature, gives us a much better understanding of these Atlantic oscillations. We now know that accelerations in sea-level rise in cities like New York and Boston on the north-east coast of the US are linked to a cold spell in the Atlantic...

Did they make worst the heating of the Long island sound last heat spell.

The Greatest Ever Thermohaline Superstorm Approaching the Millstone Nuclear plant!

Is this implicated with the North Carolina shark attacks...

Accelerated Warming of the Continental Shelf Off Northeast Coast 

June 11, 2015 

A couple of unexplained large scale changes in the waters off the northeast coast of the U.S. have oceanographers perplexed: an accelerated rate of sea level rise compared to most other parts of the world; and the disturbing signs of collapsing fisheries in the region.
A new study by physical oceanographers at Woods Hole Oceanographic Institution (WHOI), published in the Journal of Geophysical Research, shows that water temperatures in this continental shelf region have been trending upward, with unprecedented warming occurring over the last 13 years. The study also suggests a connection between sea level anomalies and water temperature along the continental shelf. 

“The warming rate since 2002 is 15 times faster than from the previous 100 years,” says co-author Glen Gawarkiewicz, a WHOI senior scientist. “There's just been this incredible acceleration to the warming, and we don't know if its decadal variability, or if this trend will continue.” 

The scientists compared their findings with a study of surface waters using data collected by Nantucket Light ship, and other light ships up and down the East Coast between 1880 and 2004, previously analyzed by Steve Lentz of WHOI and Kipp Shearman of Oregon State University. The new study shows that recent accelerated warming is not confined to the surface waters, but extends throughout the water column...

Grand Gulf’s Power History: Entergy’s Junk Southern Fleet?

June 12

Finally 100%

Update June 11

Miserable progress now at 94%. Six days to recover from a 50% down-power...  

Update June 10

at 77% today...they ain't making money at this power level. River Bend is at 66%.

Everyone in Region 1 is at 100% power.

*********************

Hmmm, River Bend and Grand Gulf is a struggling single unit facility? 

The whole deal reminds me of Pilgrim's shutdowns and power reductions over their junk new safety relief valves for six years.

It is driving me crazy why the exact same NRC event report came out on June 8 and June 9. Bet you it was a NRC screw-up, entergy came up with a update and the NRC just copied over the original by mistake today.

All plants in the same vicinity?

Grand Gulf's recent power history. 

June 9  95%

8  94%

On June 8^th at 8:15 pm Grand Gulf had a fire in their Electro Hydraulic Pump C terminal box. Again in 24 hours the reactor power level being stuck at 95% is highly unusual. 

7  79%

6  50% 

5  100%

River Bend: What A Junk Plant’s Power History Looks Like

7/20

95%

 

7/17

91%

 

7/13

What the hell, back to 63%

7/4

Finally 100% 

7/3

80%

 

7/2

80%

 

7/1

84%  

6/30

75% 

6/29

down to 74% over the weekend

6/28

31% 

6/27

50%

 

6/26

still at 94%

6/25

94%

6/24

94%

6/23

94%

6/22

94%

June 19

94%

June 18

93%

June 17

88%

June 16

River Bend is at 90% power and Indian Point 3 is a 0% power. 

June 15

Wow, great progress over the weekend. Now 89% power. At least Grand Gulf didn't trip.  

June 12

71% power 

Update June 11

At 70% power. Gained a whole lot in 24 hours, a tiny 4% power.  

Update June 10 

Well, there is progress. They are at 66%. Grand Gulf is at 77% power. Can't make money this way?

Everyone in Region 1 is at 100% power.

****************************** 

June 1: The New River Bend Feed Pump Scram?

June 9 33% reactor power
  

The started up on June 8 (actually June 7), 24 hours later they are only at 33% power? This means something is highly abnormal. It is shocking just the before scram, RB were at reduced power on May 30 and 31, upon start up they are drastically at reduced power for over 24 hours. This isn't the looks of a professional outfit? 

8 3%

7 0%

6 0%

5 0%

4 0%

3 0%

2 0%

June 1 92%-this is when they scrammed on feed level control problems.

May 31 81%

30 52%

29 100%

Grand Gulf Fire: Another Entergy plant

Power Reactor	Event Number: 51137
Facility: GRAND GULF Region: 4 State: MS Unit: [1] [ ] [ ] RX Type: [1] GE-6 NRC Notified By: RONNIE WALTERS HQ OPS Officer: DAN LIVERMORE	Notification Date: 06/08/2015 Notification Time: 00:45 [ET] Event Date: 06/08/2015 Event Time: 22:59 [CDT] Last Update Date: 06/08/2015
Emergency Class: UNUSUAL EVENT 10 CFR Section: 50.72(a) (1) (i) - EMERGENCY DECLARED	Person (Organization): JACK WHITTEN (R4DO) WILLIAM GOTT (IRD) ALLEN HOWE (NRR)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	Y	92	Power Operation	92	Power Operation

Event Text

FIRE IN PROTECTED AREA LASTING GREATER THAN 15 MINUTES At 2359 EDT on June 7, 2015, the Grand Gulf Nuclear Station declared a Notice of Unusual Event in accordance with Emergency Action Level HU4 for a fire in the protected area lasting greater than 15 minutes. The fire started in the wiring of a terminal box for Electro Hydraulic Pump C, the running pump located in the turbine building. The running pump was then deenergized by operators and the standby pump started. The site fire brigade responded and extinguished the fire. The emergency was terminated at 0030 on June 8, 2015. The licensee notified state and local agencies and will inform the NRC Resident Inspector. Notified R4DO (Whitten), NRR EO (Howe), and IRD (GOTT). Notified DHS SWO, FEMA Ops Center, NICC Watch Officer, and FEMA NWC and Nuclear SSA via email.

Employee Sabotage: Knocking Off Line The Waterford Nuclear Plant?

Update 5 pm 

I didn’t have to through decades of NRC documents to discover this. It is the newest inspection report. These are the guys who have long term issues with keeping their diesel generators operable. The DG day tank vent corrosion and not have a direct indication on DG room ventilation flow, the broken fan event.

So the below indicates an intentional and malicious attitude of Entergy with not following the rules, only following the rules Entergy thinks are valid. The below basically surrounds the facility capability to resist fires per licensing and for the crew to alternately shut down the reactor if the control room becomes uninhabitable. Most other plants have fixed this issues decades ago.

I think the staff feels, my plant’s operations is becoming chaotic...the nuclear industry has made the NRC too impotent to control the licensees. My plant is becoming dangerous to me and my community...I secretly tripped the plant hoping to drag in all the officials trying to get them to fix my plant.

Say Entergy refuses to comply with appendix R. The wrong doing has two components to it.

1) The risk of the non-compliance creating a severe core meltdown. Admittedly it would be an extremely infrequence event. This is the normal way the NRC comes up with a violation.

2) Destroying the safety culture in three components. Not carried in traditional enforcement. Traditionally the NRC treats risk as a isolated condition, while if the licensee is promiscuously with not following the rules, it creates the condition where nobody has to follow the rule. Now you got a nuclear plant staff with global integrity problem without bounds. 

  

a) If my company violated the rules and the NRC is powerless to make them to comply...this behavior means it ok for me to not follow the rules as long as I don’t get caught.

b) The idea the licensee is impervious to control by outsiders and the NRC...my company can crush me if I don’t behave their way. Make me behave contrary to my conscience, licensing and following the rules.

b) Configuring the plant contrary to licensing and the NRC rules...have no way to know what configuration the plant is in. Declaring a component is operable when management knows it is not or a employee thinks that is what management wants.

Check out how many of these violations are decades old. Even though a licencee is currently not in conformance with plant licencing... becuase it is a decades old and a current violation, this means it not a violation or can be giving  paper-cut not sited violation. Only the NRC can frame crazy language like this. 

It obvious agency and licencees contempt for following the rules. This naturally leads to chaotic plant operations and many safety components knowingly and unknowingly degraded or broken. What if you were employee in a totally out of control plant and you had many legitimate reason not to trust the agency or your company. What if you didn't trust anyone. What would you do...how would you drag attention to the agency and the plant. tripping a plant is really not safety related, but it is a attention getter.

A plant equipment operator or licensed operator got a thousand ways to trip with zero chance of getting caught. The example is in the feedpump room. Isolating a pressure instrumentation line, then open the vent line....the putting the valves back into the normal position. It would take second for this and you guarantee

a plant trip without getting caught.    

May 27, 2015: WATERFORD STEAM ELECTRIC STATION, UNIT 3 – NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000382/2015007 AND EXERCISE OF ENFORCEMENT DISCRETION

• Green. The team identified a non-cited violation of License Condition 2.C.(9), “Fire Protection,” for the failure to ensure the required separation between fire areas. Specifically, the licensee installed fire barriers on two ventilation ducts which were not in a configuration demonstrated to provide the required three-hour fire-rated separation between fire areas. The licensee entered this issue into their corrective action program as Condition Report CR-WF3-2015-00540 and established an hourly fire watch as a compensatory measure until corrective actions can be taken (Fire Impairments 15-30 and 15-31). The failure to ensure the required separation between fire areas was a performance deficiency.

This finding did not have a cross-cutting aspect since it was not indicative of current licensee performance since this fire barrier configuration was installed in the 1980s.(Section 1R05.02.b)

• Green. The team identified a non-cited violation of License Condition 2.C.9, “Fire Protection,” for the failure to correct adverse conditions associated with fire protection. Specifically, the licensee failed to correct longstanding deficiencies with the Appendix R emergency lighting units. The licensee entered this issue into their corrective action program as Condition Report CR-WF3-2015-00593 and operators had flashlights available as a compensatory measure.

• Green. The team identified a non-cited violation of License Condition 2.C.9, “Fire Protection,” for the failure to periodically test and demonstrate the 8-hour capacity of the Appendix R emergency lighting units. The licensee entered this issue into their corrective action program as Condition Report CR-WF3-2015-00856 and operators had flashlights available as a compensatory measure. The failure to periodically test and demonstrate the 8-hour capacity of the Appendix R emergency lighting units was a performance deficiency.

• Enforcement discretion. Specifically, the team identified four examples where the licensee failed to maintain an alternative shutdown procedure that successfully mitigated all postulated alternative shutdown scenarios. This finding affects 10 CFR 50.48 and has been screened and determined to warrant enforcement discretion per the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48).

A employee cry for help? More like Entergy is sabotaging plant capacity factor on a maintenance and plant upkeep ideological philosophy with putting stock price above plant safety. 

I see this kind of fire accident as extremely infrequent. But if you get to the point of having to run a diesel generator without cooling water for ten minutes with most of your safety systems already  stripped away from you, at this point to a licenced operator, one error or miscalculation has the strong possibility of creating catastrophic problems for the local community. One error has the high possibility to be stratospherically signifiant. The operator is going to be upset and his plant is in such a condition...an error is highly likely. Here is when the engineers screw the operator putting them in the position of getting blamed for the accident, with the calculation of the risk outcome of the fire being too complex to understand. This is when all their self interested assumptions will show up to screw to the operator. There just got to be simple systems and procedure at this point...it has to be absolutely be bullet proof. The system today is set up where as the consequences of a misstep increases, the operator has less qualified testing, components and procedures. As the consequences of a accident increase, the quality if the system and components decrease.  

Green. The team identified a Green non-cited violation of License Condition 2.C.9, “Fire Protection,” for the failure to adequately correct a previous violation. Specifically, the licensee failed to provide a bounding calculation for the amount of time available for operators to establish component cooling water during an alternative shutdown. The licensee developed this calculation in response to Non-cited Violation 2012007-02. Description. During the 2012 triennial fire protection inspection, the team identified a violation for the failure to perform a safe shutdown design calculation.

Just look at this, in 2012 the NRC discovers a not safe calculation in this extremely grave emergency procedure, gives Entergy a minor violation over it. The expectation is if the NRC violates them, the problem will be fixed conservatively and right. Entergy throws up the middle finger at the agency in 2012, gives them back a half ass correction to the calculation. The object is, how much time does the operator have to perform a step in the procedure without cooling water to the diesel generator before damage occurs. Have they ever done a experiment on a similar diesel generator with no cooling water...does anyone have the actual proof with how long a diesel generator  has without cooling water before failure. All they talk about these calculations and formulas without any proof they reflect the truth.   

You are in the realm here where these rules and procedures are sacred at this point..

So the NRC violates them again on their first 2012 violation and then gives them non sited green violation on a host of rules breaking over appendix R and the alternate shutdown on this inspection. You know, our rules aren't sacred. They are really telegraphing to all the employees on site following or not following the secret rules is insignificant in the big scheme of things. This occurs over and over again at this site telling the employees rules are insignificant. Management treat the NRC rule as just optional.  Basically all of risk perspectives teaches the staff that not following the sacred rules is insignificant.

At the bottom of this pile of horseshit might be one employee with a conscience thinking, my management and the federal agency overseeing the whole shebang is completely and utterly crazy. My plant is running totally out of control. Don’t you wish this employee was there in TMI or Davis Besse? Holy shit, the rules and polices of the NRC might not contain the control of this site. It won't be the first time a employee felt this in the industry. I don’t know anyone I can trust and  the outsiders won’t understand the technical issues behind my concerns. My only hope is a big attention getting ploy dragging the multitudes toward the plant's problem. This surely can fix my plant's problems.

What will happen if I secretly trip the plant? Will that sober everyone up?     

Michael Mulligan

Dear Sir, It must be an extraordinary coincident feed pump trips took out two plants (River Bend, Waterford) Entergy plants within 24 hours and 50 miles from each other. I think you need early to get

To: allegation@nrc.gov  Today at 7:48 AM 

Dear Sir, 

It must be an extraordinary coincident feed pump trips took out two plants (River Bend, Waterford) Entergy plants within 24 hours and 50 miles from each other. I think you need early to get out front of this and publicly explain these events. 

1) Entergy treating their employees in a draconian manner...is causing their employees to retaliate by sabotaging the plants. They secretly tripped Waterford to get even? 

2) Or the electrical troubles is spanning across two plants indicating it is a fleet wide problem?3) Request a special inspection and FBI investigation on the Waterford Plant?

Sincerely, 

Mike Mulligan 

Hinsdale, NH 

16033368320

You get it with unreliable equipment, a feedwater trip and issues with a automatic bus transfer that didn't occur? 

05000382

Power Reactor	Event Number: 51116
Facility: WATERFORD Region: 4 State: LA Unit: [3] [ ] [ ] RX Type: [3] CE NRC Notified By: SCOTT MEIKLEJOHN HQ OPS Officer: DONG HWA PARK	Notification Date: 06/03/2015 Notification Time: 21:36 [ET] Event Date: 06/03/2015 Event Time: 17:05 [CDT] Last Update Date: 06/03/2015
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): JACK WHITTEN (R4DO) SCOTT MORRIS (NRR) WILLIAM GOTT (IRD)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
3	M/R	Y	100	Power Operation	0	Hot Standby

Event Text

MANUAL REACTOR TRIP DUE TO LOSS OF MAIN FEEDWATER PUMP "This is a non-emergency notification from Waterford 3. "At 1705 [CDT] the reactor was manually tripped in anticipation of an automatic trip due to loss of main feedwater pump 'A'. "The plant is currently in mode 3 and stable with emergency feedwater feeding and maintaining both steam generators due to an automatic emergency feed actuation signal. "During the trip, the 'B' electrical safety and non safety busses did not automatically transfer from the unit auxiliary transformer to the startup transformer causing a loss of off-site power to the 'B' electrical busses. This resulted in a loss of main feedwater pump 'B'. "The 'B' emergency diesel generator started as designed and reenergized the 'B' safety related buses. "The plant entered the emergency operating procedure for loss of main feedwater. "Off-site power has been restored to the 'B' safety and non safety busses, and the emergency diesel generator 'B' is secured. All control rods fully inserted into the core following the trip. Decay heat is being removed by the main condenser using the turbine bypass valves. The electric plant is in a normal shutdown lineup. The licensee has notified the NRC Resident Inspector.

LER 2014-006-00: The River Bend Christmas Scram Causing the First Special Inspection

So here is the 2014 Christmas scram that got the first inspection. An event like this happens with the mixture of poor plant maintenance and general incompetence of the employees...poor training across the board.  

Doesn't it raise the hairs in the back of your neck with all degradation of components showing up in one event? 

This is a dangerous plant in many ways...

I believe the first half scram with the turbine control scam over instrumentation problem was basically a  turbine grounding problem throwing electrical spikes at the instrumentation...creating a set of scrams.

I see the problem as in many cases as  intermittent equipment and electrical problems...they really don't have a means to record the event. They are uncertain what caused it...they guess what did it or on a quick and expensive fix...then quickly startup into the next scram.   

Licensee Event Report 50-458 /2014-006-00:Automatic Reactor Scram and Primary Containment Isolation Due to Loss of Power on the Division 2 Reactor Protection System With a Concurrent Division 1 Half-scram On December 25, 2014. at 0836 CST, a reactor scram occurred while the plant was operating at approximately 85 percent power. This event resulted from the loss of power on the Division 2 reactor protection system (RPS) (**JD**) bus, in conjunction with a preexisting half-scram on Division I. The loss of Division 2 RPS power also resulted in a Division 2 containment isolation signal. Approximately four minutes after the scram, reactor water level increased to the Level 8 setpoint, causing the running main feedwater pump (**SJ**) to trip. As reactor water level decreased back through the normal operating range, operators attempted to re-start main feedwater pump "C," but its supply breaker failed to close. Main feedwater pump "A" was subsequently returned to service. As reactor water level decreased to the point at which the startup feedwater regulating valve (FRV) should have opened to establish automatic control, the valve failed to open. Attempts to open it with a manual input signal were unsuccessful, and the "C" main FRVwas put back into service. By that time, reactor water level had decreased slightly below the Level 3 RPS actuation setpoint, resulting in a second scram signal. INVESTIGATION and IMMEDIATE ACTIONS 

The Division I half-scram had been inserted two days prior to the event, in compliance with Technical Specifications, following the failure of an instrumentation channel on the no. 2 main turbine control valve. Teams were formed to investigate the separate significant aspects of the event, as follows: Loss of Division 2 RPS Bus 

Power was lost when the output breaker on the RPS motor-generator (MG) in the Division 2 subsystem tripped. The mostly likely cause of the output breaker trip was an intermittent failure of the MG field flash card due to a degraded capacitor. The capacitor was replaced, and the MG was tested and returned to a standby condition as a backup power supply. The alternate power supply will remain in service carrying the bus until completion of a modification to eliminate the field flash card as a potential source of recurrence of this problem. Misoperation of the Startup FRV The operation of the startup FRV was investigated to determine why it was unresponsive to either the automatic controller or the operator's manual input. Maintenance technicians discovered a failed circuit card in the "manual" side of the valve controller. The ".automatic" function of the controller had operated correctly in the post-scram environment once reactor water level had returned to normal, and this was confirmed again during the troubleshooting. Additionally, Engineering personnel determined that the performance of the valve was consistent with its design criteria. The valve and its control logic are designed for flow control, and not simply for isolation. When the valve receives a gradual "open" signal from the closed position, there is no specific time response requirement. This design feature can allow a delayed response that, in the scram recovery scenario, may be too slow to arrest a significant downward trend in reactor water level. Malfunction of Main Feedwater Pump "C" The failure of main feedwater pump "C" was found to have been was caused by an "over-racked" condition of its supply breaker (that is, the breaker racking mechanism had slightly over-travelled the last time the breaker was returned to service). This caused the limit switches that detect the position of the breaker mechanism within the cabinet to give the control logic circuit a false indication that the breaker was not connected to the bus. Interim instructions have been implemented to have electricians verify the condition of all similar breakers each time they are racked in.

I Now Know What Is Wrong With The NRC. It's a Alien Invasion Coming.

The Whispers Season 1 Episode #01 – XMarks The Spot Review

Posted by Chris Beveridge
June 2, 2015 at 11:25 AM

The central idea of the series is one that’s certainly an interesting one, an approach you don’t see often when it comes to alien invasion shows. At least not ones that are treated seriously when you get down to it. As we see with the prologue here, these aliens are looking for a way to take care of business by working through the children. Not just any children though, but carefully selected ones that will give them the access they need. Seeing the way a young girl is enthralled by an imaginary friend she calls Drill is certainly eerie with how it unfolds, since Harper just views it all as a game and her mother finds it cute. But when it leads to the mother’s death in a creative way, that sets things into motion since the child’s father is the head of the Nuclear Regulatory Commission. That elevates things up several notches to be sure among those that investigate such things.

March 7, 2013: Mike Mulligan's Request For Special Inspection on Pilgrims SRVs Problems

Additionally, during an extent of condition review of historical SRV performance, the review identified on March 13, 2015 that SRV-3A had failed to open in response to three manual actuation demands on February 9, 2013 with reactor pressures of 114, 101, and 98 psig.

I supposed I could have danced around in a sting bikini at the font door of the NRC's main office trying to get them to take action. Maybe that could made them act.

The media is about worthless!!! 

From: Michael Mulligan [mailto:steamshovel2002@yahoo.com] 

Sent: Thursday, March 07, 2013 12:33 PMTo: newstip~globe.com; NRC Allegation

Subject: 2.206: Pilgrim Nuclear Plant SRVRequest for Emergency Shutdown  

Dear Sir, 

I called this into your hotline by telephone and left a message to a reporter an hour or so ago. This is just a follow-up. I'd like to get Gov Patrick to demand an immediate Pilgrim shutdown and demand a special investigation of these events.  

Mike 

So the below is my 2.206 request to the NRC. You'd do me a favor if the BG calls our region I public relation people...Neil Shaheen. 

March 7, 2013

Bill Borchardt
Executive Director for Operations
U.S. Nuclear Regulatory Commission
Washington, DC 20555-0001

Dear Mr. Bochardt,

Request an emergency and for a exigent bases, that the Pilgrim Nuclear plant be immediately shut down. 

Don't tell me just before Nor'easter Nimo struck the Pilgrim plant with a leaking safety relief valve and down at 80%, Entergy was intending to operate that plant with a defective leaking safety relief valve till the next refuel outage? Tell me it ain't so. It certainly looks like with the current leak today they are intending to operate till next month. 

Is the game plan today to incrementally increase reactor power from 94% by 1% to see if a new SRV leak is getting worse? 

Timeline: 

1) New three stage safety relief valves installed in the plant around May 2011. 

2) First leak and shut down on Dec, 26. 2011 (SRV RV-203-3D). 

3) Second leak and shut down on Jan 20, 2013 (SRV RV-203-3B).  

4) Third leak occurred a few weeks later and the Nemo blizzard tripped the plant.. .the NRC promised these valves would be fixed. (SRV RV-203-3B). 

5) Basically they operated for 20 days at 100% power operation post shutdown, then reported on Feb 27 the plant is operating at 94% power with no explained reason until today. The reason for the down power was kept secret from the public.

(NRC added: EDO -- G20130174)  

Don't forget the repetitive nature of the recently broken scram discharge volume vent and drain valves...implies Entergy is incapable of maintaining safety components in a nuclear plant.  

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

They changed out the not safe 3 stage SRV valves  for new 2 stage SRVs after Juno...the NE+RC forced their hands  

are defective and it is extremely unsafe to operate in a nuclear plant with all safety relief valves being INOP. A condition adverse to quality...  

The NRC should have made a public comment about the new leaking safety relief when they first became aware of the leak. The implication is the agency was going to allow the plant to operate with unsafe SRVs until the refueling outage next month. The NRC is involved in a serious cover-up of an extremely unsafe operation in a nuclear power.  

1) Request an immediate shutdown the Pilgrim Plant.  

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

3) Not allowing 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. 

References:

The Popperville Town Hall (my blog) 

"Pilgrim's Safety Relief Valve Leaking Boondoggle"

Sincerely,

Michael Mulligan
PO Box 161
Hinsdale, NH 0345116033368320
steamshovel2002@vahoo.com

This is the agency's take directly in the lead up to the Juno's trip. There is a lot more evidence. These guys are picking and choosing what information they think is important to push  out for a organizational agenda.  

May 27, 2015: PILGRIM NUCLEAR POWER STATION – NRC SPECIAL INSPECTION REPORT 05000293/2015007; AND PRELIMINARY WHITE FINDING

• The ‘A’ SRV was not planned to be used due to previously identified pilot valve leakage, but was considered by Entergy to be available for use if needed.

The problem with the above in a past LER with pilot valve leakage, they all should know this...the leak can make the relief lift inaccurate without being detectable. It could be so inaccurate if they knew about it, they would have to intermediately shut down to fix it. It illegal to be up at power with a inaccurate SRV valve.  

• While the ‘C’ SRV satisfactorily stroked during both the setpoint test and additional low pressure (100 psig) actuation test at the testing facility, the inspection revealed notable damage to some internal valve main stage parts. Specifically, the main valve piston had indications of some scoring and the lower piston ring (two rings in total) was seized within the piston ring. The most noteworthy damage was wear (grooves) in the main operating cylinder liner where the operating piston rings rest while the valve is in its closed position.

• During Entergy’s investigation of the January 27, 2015 partial LOOP event, Entergy staff reviewed plant parameter data associated with historical SRV actuations. During the review, Entergy staff determined that the ‘A’ SRV similarly did not open during manual actuations on February 9, 2013, during a plant cooldown following a LOOP event. This determination was based on Entergy’s review of the response of reactor pressure, level, local suppression pool temperature, and SRV tailpipe temperature.

I think Entergy was actively not looking for problems with the SRV valves in 2013. They knew the mis-operation and choose not to report it. 

• Entergy identified that, during the February 9, 2013, event, operators attempted to utilize the ‘A’ SRV to reduce reactor pressure on three occasions (at 114 psig, 101 psig, and at 98 psig). The operators observed that the ‘A’ SRV did not yield the appropriate tailpipe acoustic monitor response, although tailpipe temperature did show an increase. Following the third opening without observing the appropriate acoustic monitor response, operators only utilized the ‘C’ and ‘D’ SRVs for plant cooldown [note that the operators considered that the ‘B’ SRV was less desirable to use due to previously-observed pilot valve leakage]. 

• The only action that resulted from CR-PNP-2013-00825 was the replacement of components associated with the ‘A’ SRV’s acoustic monitor. Maintenance workers identified an electrical ground on the system. Analysis. Entergy’s failure to identify, evaluate, and correct the condition of the ‘A’ SRV’s failure to open upon manual actuation during a plant cooldown on February 9, 2013, was a performance deficiency. In addition, the failure to take actions to preclude repetition resulted in the ‘C’ SRV failing to open due to a similar cause following the January 27, 2015 LOOP event.

2015-002-00: On March 12, 2015, after further engineering evaluation of performance of the valves and internal conditions identified during inspection, SRV-3A and SRV-3C were determined to have been inoperable for an indeterminate period during the last operating cycle. SRV-3C was determined to be inoperable based on its on-demand performance at low reactor pressures (first

Licensee Event Report (LER).2013-002-00, "SRV-3B Safety Relief Valve Declared Inoperable Due to Leakage and Setpoint Drift" was submitted on March 31, 2013 (Reference 1), with a target schedule of September 30, 2013 to submit a Supplement to the LER, after completing
the root cause analysis. Since then the vendor (Target Rock) has issued a 10 CFR Part 21 Notification, (Reference 2)confirming defects in safety relief valve bellows.

2013 - 002 - 01 On February 3, 2013, RV-203-3B first stage pilot valve leakage was identified while at full power. Reactor power was lowered to 80% and at 1000 psig pressure, the pilot was reseated. An Operability Determination with a compensatory measure was implemented to maintain the reactor power at 80% and reactor pressure at 1000 psig. An Operations Decision Making Issue (ODMI) was implemented to monitor and take corrective actions. During the forced outage on February 8, 2013, caused by a loss of offsite power due to a major winter storm, RV-203-3B first stage pilot valve was replaced with a new pilot valve and the plant was returned to power operation. The cause of the pilot leakage was determined to be a combination of the natural frequency issue and weakening of the pilot bellows spring. This bellows spring had a through wall failure during testing at an offsite test facility in March 2013. This failure was the subject of a Target Rock 10 CFR, Part 21 (Reference 1).The removed RV-203-3B pilot valve was sent to Wyle Laboratory for testing. 

As-found test results for the SRV, RV 203-3B pilot valve were: 

Pilot S/N SRV Position As-Found Deviation 23 RV-203-3B 1112 psig (-)3.8% Technical Specification 3.6.D.1 requires the as-found setpoint to be within 1155±34.6 psig (1120.4 psig to 1189.6 psig). The as-found setpoint was less than the minimum pressure specification required by TS 3.6.D.1. This test result was entered into the corrective action program as a separate event, and is included in this LER since the condition was discovered within 60 days from the initial discovery of pilot leakage. Accordingly, this as-found value being out of Technical Specification setpoint is reported in this LER pursuant to 10 CFR 50.73(a)(2)(i)(B).

Licensee Event Report 2013-002-01, SRV-3B SafetyRelief Valve Declared Inoperable Due to Leakage and Setpoint Drift

1/20/2013

• This condition potentially applies to all four three

The design is defective creating the damaged components. There was no way to reliability to observe or predict the degradation mechanism. They were unfit for reactor operation...they were inop from new installation and onto the Juno plant trip.

The 3 stage SRVs defective and unsafe...post last outage they were all removed. 

Lets say the main spring was so severely damaged it would fail in three cycles. It would get through all the testing, then have two cycles before failing. It would pass all test, but sitting right on the precipice of failure. Is that fully operational or inoperationl? Does getting past all the pre-operational testing mean it is operational despite the actual materiel condition of the components inside the valve. 

I am certain there would be many other problems documented in secret plant documents than this.    

stage SRVs that were installed in RFO 18. During Cycle 19 operation, Pilgrim has observed leakage from RV-203-3B, 3C, and 3D.

• On May 18, 2011 and November 25, 2011, SRV RV 203-3C second stage pilot valve minor leakage was observed. This condition did not cause inoperability of the valve. SRV RV-203-3C was replaced during the December 26, 2011 shutdown.

• On December 26, 2011, SRV, RV-203-3D first stage pilot valve experienced leakage that exceeded the operability criteria while operating at full power. The plant was shut down as required by TS 3.6.D.2, RV 203-3C and 3D were repaired and the plant returned to full power operation. The cause of the pilot leakage was later determined to be a combination of the natural frequency issue and weakening of the pilot bellows spring. This bellows spring had a through wall failure during testing at an offsite test facility in March 2013. This failure was the subject of a Target Rock 10 CFR, Part 21 (Reference 1).

• On January 20, 2013, Pilgrim experienced the event described in this Licensee Event Report, first stage pilot valve leakage of SRV, RV-203-3B. The plant was shutdown as required by TS 3.6.D.2. The pilot valve was replaced with a refurbished pilot and the plant was returned to full power operation.

• On February 3, 2013, RV-203-3B first stage pilot valve leakage was identified while at full power. Reactor power was lowered to 80% and at 1000 psig pressure, the pilot was reseated. An Operability Determination with a compensatory measure was implemented to maintain the reactor power at 80% and reactor pressure at 1000 psig. An Operations Decision Making Issue (ODMI) was implemented to monitor and take corrective actions. During the forced outage on February 8, 2013, caused by a loss of offsite power due to a major winter storm, RV-203-3B first stage pilot valve was replaced with a new pilot valve and the plant was returned to power operation. The cause of the pilot leakage was determined to be a combination of the natural frequency issue and weakening of the pilot bellows spring. This bellows spring had a through wall failure during testing at an offsite test facility in March 2013. This failure was the subject of a Target Rock 10 CFR, Part 21 (Reference 1).

The removed RV-203-3B pilot valve was sent to Wyle Laboratory for testing.

As-found test results for the SRV, RV 203-3B pilot valve were: 

Pilot S/N SRV Position As-Found Deviation23 RV-203-3B 1112 psig (-)3.8%

Technical Specification 3.6.D.1 requires the as-found setpoint to be within 1155±34.6 psig (1120.4 psig to 1189.6 psig). The as-found setpoint was less than the minimum pressure specification required by TS 3.6.D.1. This test result was entered into the corrective action program as a separate event, and is included in this LER since the condition was discovered within 60 days from the initial discovery of pilot leakage. Accordingly, this as-found value being out of Technical Specification setpoint is reported in this

• The third pilot on RV-203-3B began leaking on February 26, 2013. Leakage was controlled by reducing power and pressure per the ODMI. This pilot was replaced during the Spring 2013 RFO. The cause of the pilot leakage was that the pilot assembly had a natural frequency that was close to a resonant frequency of the valve assembly when installed on the PNPS main steam line.

What the Death Rattles in Quad Cities Nuclear Plant Looks Like???

We are watching The death spiral of Quad Cities...its death throes. So the death sentence is coming in Sept. Imagine how fearful and insecure the employees are? Exelon has been torturing these employees for years with this threatening. 

Exelon to decide fate of Quad Cities nuclear power plant in September: CEO 

Louisville, Kentucky (Platts)--29 May 2015/526 pm EDT/2126 GMT 

Exelon CEO Christopher Crane said the nation's largest nuclear generator will decide in September whether to close its money-losing, 1,824-MW Quad Cities merchant nuclear plant in Illinois.

Time is running out for Exelon to craft an economic solution for three Illinois nuclear plants -- Byron and Clinton are the others, totaling about 5,000 MW of generation -- Crane said in comments webcast Thursday from the Sanford Bernstein Strategic Decisions Conference in New York.

The Chicago-based company had hoped the Illinois General Assembly would pass Exelon-backed legislation creating a low-carbon portfolio standard to provide the nuclear plants with an estimated $300 million/year in economic support before its 2015 regular session adjourns late next week.

That appears unlikely, although lawmakers still could consider the legislation during a two-week fall veto session in November...

It is obvious Exelon knew this plant was coming to the end of their rope...why waste money on this plant when we are going to shut it down. So this is the amount of money you got to spend on the outage...prioritized the plant with maintenance thinking the it is only going to run a few more years.

So this steam leak, the shorting cable, the fires and plant electrical transient....it all started by not having enough money to fix gland seal valve packing leak. The work around from this leak. 

Look at what was needed to create this, not enough money for the maintenance budget, not following procedures, cable error in construction...the moisture took advantage of an electric cable issue creating all these fires.

What I worry about, will the financial problems broadly degrade  the components throughout a plant...setting up the plant to be in a condition outside the license.

August 12, 2014: QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000254/2014003; 05000265/2014003 

Green. A finding of very low safety significance (Green) and associated non-cited violation of Technical Specification (TS) Section 5.4.1 was self-revealed on April 2, 2014 for the licensee’s failure to establish a procedure in accordance with the requirements of Regulatory Guide 1.33. Specifically, the licensee established procedure QOP 5600-01, “Gland Seal System Operation,” for use during startup of the Main Steam and Turbine Generator systems. However, the procedure failed to include provisions to ensure that the steam seal regulator bypass valve, 2-3099-S2 (S2) was closed prior to lifting the steam seal bypass relief valve and exceeding the bypass line design pressure. That resulted in a failure of the piping and a significant steam leak in the ‘D’ heater bay. Immediate corrective actions taken by the licensee included revising their procedures for operation of the Gland Seal system and conducting just-in-time training on Gland Seal system operation for operators prior to the subsequent startup on Unit 2. In addition, the licensee planned to review and revise their operator training program for the Gland Seal system. The licensee documented this issue in CAP as IR 1642409. In June 2013, the licensee identified packing leakage from the steam seal feed valve, 2-3099-S1 (S1). In September 2013, the S1 packing leakage increased, and the licensee made a decision to close the valve. The S1 is required during startup of the Main Steam and Turbine Systems and normally kept open while operating, though the gland seal system can continue to function with the S1 closed, once at normal steam pressures. The licensee had a plan to fix this leak during the refueling outage. However, they did not include this work into a forced outage scope. The licensee was forced to shut down Unit 2 due to an unrelated issue on March 31, 2014, and attempted to startup on April 2, 2014, prior to repairing the S1 valve. The packing leak on S1 caused the operators to have trouble while starting up the Gland Seal system, as described below.

It just looks like we are setting up the conditions of a big scalding event(feed system or steam) at plant with multiple deaths and injuries...maybe electrocution. Generally a big steam or boiling hot water leak...it is a nasty accident with short all over the plant. Would a high pressure and temperature feedwater pipe break be easier on a new plant or a old plant with degraded cables... 

An insider would know in the of the SJAE and the heater bay room...it is very elevated temperature area. It is just the run-to-failure option. At some point before relicense, they should proactively replace all the cables in the high temperature area. It doesn't take many brains to figure electrical cabling in a high temperature room need to be replace often. 

This is what the death throes look like with prolong grossly insufficient maintenance budget...it is the death rattle.

The titles in the list of recent LERs looks like a junk yard!!!