Arkansas Nuclear One: Reactor Power Running Completely Out of Control

Arkansas Nuclear One and Arkansas are ground zero for tornadoes!

US tornado risk map: This map features the US regions which are prone to strong winds, hurricanes and destructive twisters. Found on: blacksamcashinterestingthigs.blogspot.com

Right, these guys have tornado warnings all the time. Basically I bet you the history is they come and go harmlessly within a half an hour or so. Bet you the shift supervisor thought, I will lollygag around trying to shutdown…it will all clear away in minutes and I will save my company tons of money instead of scramming both plants.  

This hasn't been covered in a inspection yet...these guys are so dangerous...the whole entergy fleet. They are dangerous for our nation!

The most recent NRC inspection 

Wiki: Overall, the tornado remained on the ground for an hour, from 7:06 p.m. to 8:06 p.m. (0006 – 0106 UTC), and traveled along a 41.3 miles (66.5 km) path. Sixteen people lost their lives due to the tornado,^[16] making it the deadliest in Arkansas since an F4 killed 35 on May 15, 1968.

Tornado path  

Tornado Path  

Russellville is about where ANO was.   

So the massive EF 4 tornado passed about 50 mile east of the plant. Why didn’t they just scram? If the tornadoes was directly heading right for them,  would they bungle it by doing the normal shutdown. Right, the time frame in the LER is from 1912 to 2002. The EF 4 tornado was passing 50 miles to the east of them...between them and Little Rock. I bet you the whole front that passed directly over them had dire warnings of intense tornadoes.  The tornado began at 7:25 pm and completed at 9:24 pm.  You get it, the Tornado began at 7:25 pm on April 27, 2014, with the system operator saying we are in a grid emergency telling the ANO to come off the line as soon as possible at 7:34pm…
Man, have these plants been off the line so much for stupidity in the last few years...

This gives you an idea of how much planning time they got before a tornado hits.

Description. On April 23, 2010, Units 1 and 2 were notified of a severe thunderstorm warning at 1:50 p.m. Procedure OP-1203.025, "Natural Emergencies," Revision 30 was entered. At 3:25 p.m. the licensee received a tornado warning, transitioned into a tornado watch at 4:12 p.m. and exited the watch at 8:00 p.m. The resident inspectors observed entry into the procedures and subsequently performed a site walkdown to ensure all potential missile hazards were identified and controlled as directed in the natural emergencies procedure.

>>>You got to the know the stimulator should have picked up the bum reactivity procedure...bet you the simulator modeled this inaccurately...

...to go over the high ponts of how they are going to shutdown or downpower the reactor and the issues near refueling.

... By the way, I doubt they could see real power level. They had no idea where power was…the power reading shown by the detectors and meters up in the control room were wildly are inaccurate. Don’t worry, this is normal…

 Arkansas Nuclear One: Reactor Power Running Completely Out of Control

The NRC’s ROP’s is tolerating nuclear plants running widely out of control and this government regime or oversight don’t cause bad operator to change their bad ways.

This is the same event as 2010...they don't learn from earlier near misses. So Entergy has all this NRC activity concerning the stator yellow finding, killing of the one and injuring 8 others, the so called internal changes out of this...and these events happen over and over again as if the NRC has just the power of a gnat.

These guys are extremely dangerous and are a threat to the whole US nuclear industry, for that matter, nuclear power worldwide.

A review of the ANO corrective action program and Licensee Event Reports for the previous three years was performed. There was a similar condition relative to the effects of ASI found in 2010 at ANO-2. The ASI TS limit was exceeded during a planned down power. The cause was identified to be an inaccurate reactivity management plan which contributed to the crew not being aggressive enough with ASI control.

Unit 1: March 31, 2013,

Axial Shape Index Trip at the End-of-Life During Rapid Plant Shutdown

ANO: 04 26 2014

Licensee Event Report 50-368/2014-003-00

During severe weather on April 27, 2014, both units at Arkansas Nuclear One (ANO) were informed of a system-wide grid emergency and were ordered to come off-line as soon as possible. Both units commenced a rapid plant shutdown. ANO, Unit 2 (ANO-2) was at the end of the core life. During the shutdown, the Axial Shape Index (ASI) became more negative (power rising to the upper portion of the core) during the shutdown.

This led to one channel of the Plant Protection System (PPS) to be actuated on an ASI auxiliary trip. At this time, the direction to manually trip the reactor was given, but before the action could be taken, an automatic reactor trip occurred due to the two-out-of-four PPS logic being made up for the ASI conditions. The cause of this condition was not effectively executing the reactivity management plan by delaying insertion of Control Element Assemblies (CEAs) and not inserting CEAs deep enough to maintain ASI within the desired control band.

Crane accident had ‘substantial’ safety significance,reports US regulator

2 July 2014

A March 2013 crane accident at Entergy's Arkansas One nuclear power plant that killed one worker, injured eight others, damaged the plant and required days of backup emergency diesel power was judged to be of substantial safety significance by the US nuclear regulator.

Workers were moving the 525-­ton main generator stator out of the plant's turbine building during maintenance when a temporary lifting assembly collapsed, causing the component to fall, damaging plant equipment, killing one person and injuring eight others.  

Unit 1 was in a refuelling outage at the time, with all of the fuel still in the reactor vessel, safely cooled. 

The stator fell on and extensively damaged portions of the Unit 1 turbine deck and subsequently fell over 30 feet into the train bay. The stator drop resulted in a Unit 1 loss of offsite power for 6 days and a Unit 2 reactor trip and loss of offsite power to one vital bus. The dropped stator ruptured a common fire main header in the train bay, which caused flooding in Unit 1 and water damage to the electrical switchgear for Unit 2. The alternate alternating current diesel generator (station blackout) electrical supply cables to both units were pulled out of the electrical switchgear and the diesel was therefore not available to either unit, according to a 24 March 2014 follow-up inspection report (NRC document ML14083A409). 

Unit 2, which was operating at full power, automatically shut down when a reactor coolant pump tripped due to vibrationscaused by the heavy component hitting the turbine building floor when it fell. Unit 2 never completely lost off-­site power, and means existed to provide emergency power using the diesel generators, said the regulator in a press release. 

In September 2013, the US government's Occupational Safety and Health Administration cited Entergy and three contractors, Precision Surveillance Corp, Bigge Crane and Rigging and Siemens Power Generation for 26 safety violations. 

The nuclear regulator blamed Entergy for approving a temporary gantry design not supported with adequate documentation, for failing to identify load deficiencies in the vendor's calculations, failing to identify a component of the wrong size in the north tower. It also said that the tower was not designed for 125% of the load, and inadequate load testing (including a 125% proof load test) was carried out before the lift. 

Initially, the regulator assessed the risk significance of the event at the highest level, red, for unit 1, and at the next lower level, yellow, for unit 2, but reduced the unit 1 significance to yellow after Entergy gave evidence in a 9 May conference arguing that there was a high likelihood of success (90%) for recovering electrical power to cooling pumps before water in the core boiled away, exposing fuel. 

An Entergy spokeswoman said: "Entergy is dedicated to the safe operation of Arkansas Nuclear One, and we take the NRC's findings very seriously. We are committed to learning from this tragic incident, sharing our knowledge with the industry, and ensuring that it never happens again." 

As of early July, the nuclear regulator was still determining what its response to the incident would be.

Training material is being modified to include details on the dynamic effects of ASI change that occurs at the end-of-cycle. Additionally, improvements to the guidance in the reactivity plans that involve rapid plant shutdowns are being made as are changes to the standards for use of CEAs during transients.

During the shutdown, the operator performed manual turbine load reductions, CEA insertions, and was responsible for the boration. Multiple alarms were received throughout this event due to the continuous storm activity (lightning strikes on the grid). In addition, there were multiple phone calls from the SOC dispatcher concerning the state of the grid, the down-power, and related issues. These distractions were determined to be a contributing cause for the automatic reactor trip.

The reactivity management plan was not effectively executed due to lack of specific training on understanding the magnitude and rate of ASI shift that occurs at the end of a fuel cycle and the optimal approach to control ASI during the performance of a rapid plant shutdown at the end of core life. 

Not have adequate procedures or training issues is an excuse...

The approved reactivity plan that was being used during this event included target CEA positions that reflected CEA insertions of 17 to 19 inches being necessary to keep ASI on target between each of the provided 15-minute intervals. Reactivity plans are written to 15-minute intervals for timing the expected CEA insertions and boration rates needed to maintain ASI on target through the prescribed maneuver. The rate of CEA insertion needed was only evident in the numerical CEA position targets provided in the plan. There was no additional guidance on rate of insertion or size of insertion steps provided in the text of the plan. The operator delayed CEA insertion over the initial interval because it was noted that ASI was tracking closely with the target ESI early into the maneuver. This delay in CEA insertions was found to be a direct contributor to the challenges associated with maintaining ASI in the desired control band which ultimately led to the automatic reactor trip.

In other words, when the moderator temperature coefficient heads towards the postive direction the safety feedback of  the cofficient become much less...when the coefficient becomes positive, as the coolant temperature increases, this adds reactivity uncontrollably. This is the Chernobyl. This is the ABC's of nuclear professionalism.  

Due to the negative moderator temperature coefficient that exists at low boron concentrations, control of ASI in the ANO-2 core, is challenging during end-of-cycle maneuvers. The magnitude of the temperature-driven ASI shift requires aggressive insertion of CEAs during end-of-cycle power reductions. The delay in the insertion of the CEAs and the smaller rate of insertion than needed resulted in the TS limit being exceeded.

A review of the ANO corrective action program and Licensee Event Reports for the previous three years was performed. There was a similar condition relative to the effects of ASI found in 2010 at ANO-2. The ASI TS limit was exceeded during a planned down power. The cause was identified to be an inaccurate reactivity management plan which contributed to the crew not being aggressive enough with ASI control.

Defective Scot 29er Aspect 940 Bike?

OMG: two full days of bike riding and no flat tires yet...

July 8: This company is such a dick....I am so happy I am out of them. Bought a equivalent Treck. Around my house and even in some pretty ratty tires, I get about one flat a year, if that. Within two hours of bringing the new bike home, a flat in the front tire, then next day after another two hour ride, another flat tire but on the back...come on!

Treck Excalibur 6 with bobterger tires…abouts$ 700. We like the Scot paint job better but maybe the cars will see me better.

To Me

Today at 12:37 PM

Hi Mike,

Thank you for contacting SCOTT SPORTS.

I’m sorry to read that you have gotten some thorns in your tires and punctured the inner tube. This is a very common, unfortunate part of riding bicycles. We do not consider thorn punctures a defect, but rather a part of normal riding. Please work with Norms to repair this 2nd flat tire, and I’ll hope that you’re luckier than you have been during your first few rides.

Take care, thank you for buying and riding SCOTT Bikes

Ben

Ben Chournos
Warranty & Technical Dept
SCOTT SPORTS USA
651 West Critchlow
Ogden Utah 84404

OFFICE: 888-607-8365 ext 2019
FAX: 801-627-8014
SKYPE: benchournos
warranty@scottusa.com
bchournos@scottusa.com
www.scott-sports.com
JOIN US ON FACEBOOK!
www.facebook.com/scott-sports

July 8: Well, I am off to Concord to purchase my new bike again. I don’t really feel good about it like the first time. I don’t want to get hurt again. These bikes are come from China and use the same parts…

 


I bought a Scot 29er Aspect 940 Mountain bike in a Keene bike shop this past Thursday for $650. I took two rather light bike rides around town during this. Spent about two hours riding on the road and less than an hour riding on mostly railroad trails on each trip.

I woke up on the morning after the first ride…my front tire has a flat tire. My bike has a warranty on it. I am smart enough to bring it back to the shop. I watched them change the tire…they find a really small thorn that pushed through the middle of the tire thread. I can hardly see the bush thorn it was so small. My first instinct was the tires are defective. But I am in love with the bike…so I didn’t say anything. I am thinking the owner would throw me a new tube because I am so unlucky or patch it up for free…but he charged me for it. A little more than two hours on a brand new $650 bike…I told them I must have won the million dollar lottery with this kind of luck. I intentionally told them I don’t have the $5.00 for the new tube and I will come back on saturday with the five bucks.

I take the second right on the bike. I become even more in love with the bike. But I am still a little irked about the flat tire on the first ride. I saying it is a one off…I probably won’t have another flat for two years. Next morning, well two days later because Friday was the Fourth of July...I wake up to an unbelievable second flat tire and now it is the back tire. I am outraged. I have a talk with the owner of the little shop on the phone…I can tell he becoming irked with me. I tell him I consider him as a professional…he sees bike troubles all the time. He tells me this kind of thing is normal and I say my extensive experience with bike riding says this is extremely abnormal.

I head right out to his shop. I bring the back wheel off my old bike. The tire on it is three years old and I purchased it from his shop. I never had a flat on this tire. The puncture is on the side of the tire and he can't tell what caused it. Well, he said something small punctured the tire and it didn't stay stuck in the tire. He says something punctured it without any evidence. I say it is a tube defect. So show me your proof it was pierced I asked. He becomes incensed with my attitude.

I can see the angle he was taking was everything was my fault and this happens all the time.I can see it from the very first flat when the technician asked if I took a hard fall off the bike...like I was abusing the bike. I never raised my voice to him…but I kept saying I don’t trust what you are saying anymore and this whole event poisoned my experience with this shop and the Scot brand. I would have been happy if he just put on new tires. I surmised he might refund my purchase price. He ended up unhappily refunding my money. He made a few nasty remarks as he was writing the check…I said, as our relationship has come to an end, it is pointless for me to make any further comments.

I was really happy with the brakes and shifting …the feel of the bike  was really good. It is just about the tires. I kept thinking the future is nothing but maintence problems with the bike because of cheap parts. I realize it is on the rather cheaper end of the price of mountain bikes...but not the $500 bikes or walmart bikes.

I bet you this would have been a great bike and I would have been very happy over it...if they would have put good quality tires on it. Or if I had enough money to waste another $60 to put good quality tires on it.

I am exhausted and bummed by the whole deal... 

Palisades Annual Proctoscopy

I spoke by phone in the annual meeting. It was horrendous all the sweet talking going on with Palisade and Entergy…they had finally seen the light. I said, this Entergy company killed one employee and injured 8 other by maliciously not following procedures a year ago.

I talked about the repetitive nature of events like security, the safety injection cooling water tanks, all the leaks and replacement of the CRDM, and the RCP pumps...it is disgraceful the NRC can't turn around a company at the first opportunity. The NRC just doesn’t have the skills and education to figure out what it takes to turn around company like Entergy. It is in all our interest not letting a company get this bad and it waste rate payers monies

 

Former Palisades workers claim retaliation for raising concerns

Former workers at the Palisades nuclear plant are accusing management of lying to regulators about attempts to fix a work environment where managers put a chill on critical feedback from employees.

The Palisades nuclear power plant near South Haven.

Thursday night’s meeting to review Palisades' performance last year started out pretty typically.
Regulators noted a survey that found security officers fear retaliation if they raise certain concerns.
Company officials got a chance to respond. Otto Gustafson, Director of Regulatory and Performance Improvement at Palisades, said management is taking the concerns very seriously and outlined a plan to correct the problem.

But then Chris Malich stepped to the microphone during the public comment portion of the meeting and called Gustafson and other officials out.

“I’ve seen it over and over,” Malich told regulators, “They’ve said things are going to change, things are going to change, and they stay the same.”

Malich says he worked security at Palisades from 2009 until he quit earlier this year.

Jessica Tenhagen followed Malich with more complaints. She worked at Palsisades since 2008. She believes she was fired last month because she continued to raise concerns about excessive overtime and a number of safety-related issues. She says management is well aware of the chilled work environment.

“I feel that Palisades management, all the way up the chain, is acting completely unethical. I believe they lie in their responses to (federal regulators). I believe they lie to the public. And the safety of the security officers, the public and the environment are put at risk if they’re allowed to keep running the facility under the same management,” Tenhagen said.

Chris Mikusko followed. He worked security at Palisades for 28 years. He says over the past three years, he and his co-workers repeatedly raised concerns to Palisades’ top manager, Site VP Tony Vitale.

"I believe they lie.... And the safety of the security officers, the public and the environment are put at risk if they're allowed to keep running the facility under the same management."

“It wasn’t just a sampling of the security force. It was the whole security force. All four teams brought up concerns of hostile work environment, chilled work environment, no communication. He listened to all four teams, all four of them and he says ‘I’m hearing the same message from all four’ and nothing was ever done,” Mikusko said.

Malich said he and others within the department believe Mikusko and another supervisor were fired in retaliation for continuing to raise concerns.

“They were looked at as being, as having a bad attitude because they weren’t going with management’s expectations – basically let it go, just let it go, keep letting it go, eventually (regulators) will forget about it and they’ll move on,” Malich said.

Entergy, the company that owns Palisades, would not comment on personnel issues.
But Gustafson did admit during his presentation there's a “fundamental” communications problem within the security department.

He says no one is being terminated for raising concerns, even though that’s the perception according regulators’ inspection. He says security staff needs to know about the company’s plan to improve the “safety conscious work environment.” He also says the company will work to make sure workers who raise concerns are getting updated on whether those concerns are being resolved.

“You obviously have a sender, you have a receiver, but the sender needs to validate that the receivers understood the message – we have failed with respect to that and we vow to improve that.” Gustafson said.

Regulators say it’s too soon to tell if anything the three former employees specifically raised will change their enforcement actions at Palisades.

But the Nuclear Regulatory Commission’s Kenneth O’Brien, Deputy Director of Reactor Projects Division, noted some frustration with Palisades. The plant had to completely overhaul its internal communication efforts after a series of safety-related issues in 2011 and 2012.

“The fact that we identified this as a continuing issue is a concern to us. We would’ve expected your process, your corrective action program, to have identified that before we got there.” O’Brien said.

Failed Bolts Bedevil a Nuclear Plant

July 30

$ 33 million is mere pennies for these guys...it like the cost of a hair cut.

 An extended repair shutdown at PSEG's Salem Unit 2 nuclear plant helped shave $33 million from companywide earnings during the second quarter of this year, with profits off 36 percent overall compared with the same period last year.
Despite the result, Public Service Enterprise Group Chairman Ralph Izzo on Wednesday said the diversified company still expects to finish the year with operating earnings as high as $1.395 billion, with its activities "well-positioned to generate solid earnings and fresh cash flow."
Net income for the quarter ending June 30 was $212 million, down from $333 million last year, with income of 49 cents per share for the second quarter of 2014 compared with 48 cents last year and an estimate of 52 cents for this year.
PSEG, one of the nation's 10 largest electric suppliers, is a New Jersey-based energy holding company with four operating units and $30 billion in assets. Its units include PSEG Power, which owns the Hope Creek Nuclear plant and a majority share of the Salem Units 1 and 2 reactors, all on Artificial Island along the New Jersey side of the Delaware River southeast of Port Penn

Failed Bolts Bedevil a Nuclear Plant

Neil Sheehan

Public Affairs Officer

Region I

Truly novel issues are, generally speaking, few and far between at U.S. nuclear power plants. Whether it’s a specific type of pipe that springs a leak or an electrical relay that goes on the fritz, chances are good that the problem has been experienced before somewhere across the nation’s fleet of commercial power reactors during the many decades they have been in operation.

An issue that has drawn attention at the Salem Unit 2 nuclear power plant, a pressurized-water reactor in southern New Jersey, has to do with the failure of small bolts contained in four reactor coolant pumps. The bolts, measuring 1 inch in diameter and 4 inches in length, are used to secure a turning vane inside the pumps.

Ok, the huge events the NRC reports on with inspection reports. Say a huge blade flung off a impeller that can be seen up on the control room recorders and like another huge impeller blade stuck between the vessel and core flow shirt like in this past outage at palisades. All the other rather small broken blades or recirculation damaged discovered in a outage inspection is not reported to the public. Or operating outside the manufactures recommendations are not reported on. The plant does a lot of internal investigation and documentation…but the NRC never reports on these events until a big incident arrives on scene that embarrasses everyone.

These pumps stand about 30 feet tall and provide forced flow of coolant, or water, through the reactor to transport heat from the fuel to the steam generators. The steam generators, in turn, make use of that heat by converting it to steam. The steam is then piped to the turbine to spin it and generate electricity.

(This is the NRC blog picture...it is not the Salem pump with defuser. It is the wrong picture and it doesn't show a diffuser or turning vane.)  



As can be seen in the graphic, water is drawn upward through the suction nozzle at the bottom of the pump via an impeller. The turning vane directly above the impeller then redirects the water toward an opening on the side, from which it flows into the reactor vessel.

When a refueling and maintenance outage began at the plant this spring and evaluation and maintenance work got under way, a number of turning vane boltheads were found in piping associated with one of the reactor coolant pumps and in the reactor vessel. (Similar discovery of these boltheads, albeit just a handful of them, had been observed in two prior outages.) Subsequent reviews, which have now included the examination of all of the pumps, have identified dozens of failed or sheared turning vane bolts in all of them.

Each pump has 20 such bolts. (The arrow shows the approximate location of the bolts.) A majority of the failed boltheads, though separated from the bolt shanks, remained in place thanks to mechanical restraints or tack welds.

While this is not a significant safety concern in terms of potentially causing a reactor core damage accident, there are several related operational issues. For one, the boltheads are considered foreign material that could have an adverse impact on reactor coolant system performance if they were to impact key components inside the system. For another, the turning vane could conceivably drop down and come into contact with the impeller and impede or halt its functioning.

The cause of the bolts’ failure remains under review, but one possibility is stress-corrosion cracking. Indeed, the NRC issued Information Notices to the industry in the 1990s regarding this phenomenon.
A 1994 Information Notice put out by the agency was designed to make the industry aware of stress-corrosion cracking that caused turning vane cap screws to fail at the Millstone Unit 3 nuclear power plant. Also, a 1990 Information Notice discussed the failure of turning vane bolts at a foreign reactor.
In a 1995 Information Notice, the NRC made plant owners aware of the loss of integrity for bolt-locking devices in the turning vanes of reactor coolant pumps at the Seabrook nuclear power plant but for a different reason: flow-induced vibrations.

PSEG, the owner and operator of the Salem and Hope Creek plants, will have to not only repair the Salem Unit 2 pumps but evaluate what went wrong. For now, the plant remains out of service while this work is taking place. NRC inspectors and specialists will closely follow these activities.

One area for consideration will be whether the problem could have been avoided based on previously available information.

(Note: I believe diffusers and turning vanes are the same thing)

My Response on the NRC Blog:

Mike MulliganJune 26, 2014 at 11:49 am

My blog: http://steamshovel2002.blogspot.com/

Well, another question, why didn’t the NRC have the skills and education to figure out the importance of this emergent new information and use their influence to head off a worsening situation? I do get it with the NRC and these utilities with their nothing-ever-matters philosophies and every egregious and unprofessional behavior is always safe. Why can’t the agency use their influence and power to head off events like this for the good of the nation and the rate payers? Why is their so much unnecessary secrecy with RCP?

I request all plants with identical and similar pumps to be immediately shutdown for inspection…
What is the worst sin in this deal, this has been a cover-up! Events like this aren’t reportable with the RCP and recirc pumps and disclosed to the public. Why are problems like this so secret? All broken parts like this and inappropriate maintenance issues should be in a LER and discussed thoroughly in a inspection report. This doesn’t happen now and you know it! The Palisades PCP broken impeller pieces and blades flung all around in the coolant for over decades is an example of this also.

By the way, we are wondering if the broken blades in Palisades and the shutdown for the seal job ongoing now are related? What pump is the seal job? Is the seal job the same pump who was found with two huge missing impeller blade pieces this last outage?

• steamshovel2002June 26, 2014 at 2:16 pm
  

  I bet you Salem was operating outside the pump design and plant licensing like Palisades…this is cavitation and NPSH related?

 

• Call me crazy, I don’t think the NRC used the right reactor coolant pump picture. They got up the one without the diffuser?
   

Salem, Hope Creek and Palisade Primary Coolant Pumps

Salem, Hope Creek and Palisades….

Tom Gurdziel

Good morning,

Tom Gurdziel tgurdziel@twcny.rr.com

Sunday, June 22, 2014 10:04 PM

CHAIRMAN Resource

Screnci, Diane

PSEG/Hope Creek Recirculation Pump B

1 recently stated that PSEG ran a troubled pump many hours past the recommended inspection interval, but I did not remember the specific numbers.

You will find the actual numbers in ML050100194. The inspection was recommended by GE SIL 459 at 80,000 hours. At the time this (ML) document was written, you will find in the second paragraph of page A-1 that Recirculation Pump B had been run 130,000 hours. How many it had when it actually got its shaft replaced, I do not know.

Thank you,

Tom Gurdziel

From: Screnci, Diane

Sent: Friday, June 20, 2014 8:34 AM

To: Tom Gurdziel; CHAIRMAN Resource

Subject: RE: PSEG/Salem 2 Reactor Coolant Pumps

Just an FYI- there was an event notification on Monday of last week http://www.nrc.gov/reading-rm/doccollections/ event-status/event/2014/20140609en.html, which prompted Bill Gallo's (and other) story. Also PSEG put out a press release about this in May, so there was news coverage then, as well.

Subject: RE: PSEG/Salem 2Reactor Coolant Pumps

Good morning,

Well, I just read about the Salem 2 bolt problem. (Bill Gallo, Jr./South Jersey Times.} It really wasn't hard to find on the Internet: as long as you already knew about the problem. If you didn't know, let me tell you, you weren't going to find it.

I have a couple of problems, and you should, too.

First off, is intergranular stress corrosion cracking iM their current pump aging management program, or didn't that start yet?

Second, since this is a PWR, (like the SONGS ones were}, does it also have a "loose parts monitor'' that had procedures that required no operator action no matter how many times a year, (like 30, that is a three and a zero}, the alarm comes it (as it did at SONGS)?

Third, would you think that some sort of information should have been provided by the US NRC to the public, or would that have been too transparent?

And, finally, you need to have someone explain to you how much trouble PSEG had at their Hope Creek plant a few years ago with a reactor recirculation pump that was run many thousands of hours past the vendors suggested (tear down) inspection time while they continued to monitor (but not fix) the excessive and unexpected (by them) pump vibration. My feeling is that they now should have been especially observant of problems on big pumps. Don't they do predictive maintenance on big pumps (and their motors)?

Thank you,

Tom Gurdziel

Mom & Dad had Public Service Electric & Gas, (now PSEG), stock since I was a kid. I have some of it now and am not happy with what I see here of continuing big pump problems.

Reactor Recirculation Pump Vibration Review

Background

The “B” Hope Creek reactor recirculation (RR) pump has had a historical problem involving

high vibration levels—about double those on the “A” RR pump. Past licensee actions to

reduce the vibration levels have not been effective. The high vibrations have been attributed,

in part, to a slight bowing of the shaft in the area below the seal package area. The vibrations

have led to frequent seal replacements (1.5-year intervals versus the expected 6-year

intervals).

In addition to the bowing, the “A” and “B” RR pump shafts are expected to have some degree

of thermally induced stress cracking based on industry operating experience described in GE

Service Information Letter (SIL) 459. GE SIL 459 recommends three actions to address this

problem: vibration monitoring, shaft inspections after about 80,000 hours of operation and

action to mitigate the thermal stress initiators. Hope Creek’s RR pumps have over 130,000

hours of operation, and PSEG has not performed the recommended inspections.

In addition to the pump vibrations, there are vibrations on the associated RR and RHR system

piping which have resulted in damage to system sub-components (MOV handwheel and limit

switches). To date none of the vibration-induced component problems have rendered any

safety-related system inoperable.

Sargent and Lundy (S&L) performed an independent assessment for PSEG which concluded

that return of Hope Creek to service for the next operating cycle was acceptable given the

current level of RR pump and piping vibrations. S&L’s conclusion was based upon data which

indicated that the vibration level for Hope Creek’s “B” RR pump was consistent with RR

pumps at other facilities and also based on an assumption that operators would be able to

respond to an increasing vibration trend and take action to remove the pump from service

prior to shaft failure.

The S&L assessment is summarized in the report, “Independent Assessment of Hope Creek

Reactor Recirculation System and Pump Vibration Issues,” dated November 12, 2004. The

staff reviewed the S&L report and developed a number of questions which were provided to

the licensee on December 1, 2004. PSEG responded to the questions during a December 17,

2004, public meeting with the NRC. PSEG provided an additional response to the staff

questions in a December 22, 2004, submittal. In addition, numerous teleconferences were

held between PSEG and the NRC in December 2004 and January 2005 to discuss the “B” RR

pump vibration issue.

The S&L Report concluded that there is no immediate need to replace the “B” pump rotor

during the current refueling outage. S&L recommended that both pumps be monitored for

vibrations and that a rapid rise in vibrations would be a sufficient reason to shut the pump

down immediately for an internal inspection and shaft replacement, as the window between

the rise in vibration and potential shaft failure is expected to be small.

A-2

PSEG also provided additional background information in Report H-1-BB-MEE-1878, “Hope

Creek ‘B’ Recirculation Pump Vibration Analysis,” Revision 1, dated December 16, 2004.

The report concluded that, while the “B” RR pump has elevated vibrations when compared to

the industry average, these vibration levels are not detrimental to the operation or reliability of

the pump. The report also indicated that, although the risk of a RR pump shaft cracking event

during any given cycle cannot be quantified, the operating experience of 29 RR pumps in

operation longer than the Hope Creek “B” RR pump provides sufficient data to conclude that

the risk of a shaft cracking event during the next cycle is minimal.

Staff Review

The staff review focused on the following key issues regarding the RR pump operation:

(1) Does PSEG have a technical evaluation which shows that the RR pumps can be

operated for another cycle without failure of the shafts considering the identification of

shaft cracks that have been observed at other facilities with the same design RR

pumps?

(2) Can PSEG provide data which demonstrates that shaft cracks have been detected at

other facilities with the same design RR pumps using vibration monitoring? Can the

cracks be detected in time for the operators to take appropriate actions?

(3) What are the consequences of a RR pump failure during plant operations?

GE SIL 459 indicates that all Byron Jackson RR pump shafts inspected have shown some

degree of thermally induced cracking. The cracking occurs near the pump thermal barrier

where mixing of cold seal purge system water and the hot reactor coolant water occur. The

cracks initiate as axial cracks in the pump shaft. The licensee indicated that, if the cracks

remain axial, the cracks will grow slowly and not affect the operation of the pump. However,

the licensee also indicated that given sufficient mechanical loads, the cracks can become

circumferential. The circumferential cracks can propagate to shaft failure under mechanical

loading. The time it takes to transition from slow growing axial cracks to more rapidly growing

circumferential cracks depends on the magnitude of the mechanical loads acting on the pump

shaft. Since the licensee does not know the magnitude of the mechanical loads, it is difficult

to predict the shaft life based on the magnitude of the operational loads.

The licensee has cited operating experience of other BWRs with similar Byron Jackson RR

pumps. The licensee indicates that the age of the Hope Creek RR pumps is about average

for the pumps of similar design at other BWRs. The staff notes that a number of the older

pumps included in the licensee’s comparison are much smaller than the Hope Creek pumps.

While the operating experience provides some confidence that the pumps can be safely

operated beyond the time interval recommended in GE SIL 459, the crack growth analyses

provided by the licensee indicate that the time is highly dependent on the magnitude of the

mechanical loads which are not well known.

A-3

The licensee also provided the level of vibration recorded at other BWRs with similar Byron

Jackson RR pumps. The licensee concluded that measured vibration levels of the Hope

Creek RR pumps are within the range of the vibration levels measured at other BWRs.

However, the level of vibration of the “B” pump is toward the high end of the range of vibration

levels measured at other BWRs. Therefore, the “B” pump is experiencing higher vibratory

loadings than most of the pumps in the licensee’s survey. In addition, the licensee cited a

history of problems in its attempt to balance and align the pump shaft. These problems

caused additional mechanical loadings on the pump shaft which could increase the potential

for circumferential cracks to have developed in the shaft. On the basis of the above

discussion, the staff concludes that the probability of a pump shaft failure of RR pump “B”

during the next cycle of operation is indeterminate based on PSEG’s evaluation of the

potential thermal and mechanical loads on the pump shaft.

The licensee relies on vibration monitoring to detect circumferential cracking of the RR pump

shaft with sufficient lead time for operators to secure the pump from complete shaft failure.

The licensee developed a plan for monitoring the vibration levels of the RR pumps. The key

elements of the plan involve continuous basic monitoring of the overall level of vibration and

continuous monitoring of the vibration harmonics for enhanced detection capability of potential

shaft cracking.

The licensee’s continuous basic vibration level monitoring by the operations department

consists of a pump vibration alarm and pump speed reduction if the “B” pump vibration level

reaches 11 mils (0.011 inch), and removal from service if the pump vibration level reaches 16

mils (0.016 inch). The continuous monitoring of the vibration harmonics consists of pump

vibration alarms and pump speed reduction if the synchronous speed (1X) vibration

amplitude, two times synchronous speed (2X) vibration amplitude, 1X phase angle, or 2X

phase angle exceed defined allowable limits. If the monitored values do not fall within their

allowable limits at the reduced pump speed, the licensee will remove the RR pump from

service. The allowable limits are established using ASME OM Standard, “Reactor Coolant

and Recirculation Pump Condition Monitoring.” The licensee will record baseline data to

establish these allowable limits during plant startup. The licensee provided two technical

papers in support of the proposed vibration monitoring criteria.

The first technical paper is entitled, “Case History Reactor Recirculation Pump Shaft Crack,”

Machinery Messages, December 1990. The paper discusses the RR pump shaft cracking

experience at the Grand Gulf nuclear power plant. The paper indicates that the vibration level

increased rapidly over a three hour period before the pump was secured at slow speed.

Although the shaft did not experience a complete failure, subsequent inspection revealed the

shaft was cracked approximately 320 degrees around the circumference. The paper indicates

that it is necessary to monitor the 1X and 2X steady state vectors (1X and 2X amplitudes and

phase angles) on a continuous basis and to compare these monitored values to an

acceptance criteria. The paper also indicates that alarms are necessary to alert the user to

amplitude and phase deviations that are outside the acceptance criteria.

The second paper is a Technical Bulletin from Bently, Nevada, “Early Shaft Crack Detection

on Rotating Machinery Using Vibration Monitoring and Diagnostics.” The technical bulletin

indicates that shaft cracking can be detected by monitoring the 1X and 2X vectors. The

technical bulletin also recommends continuous monitoring of machines that are susceptible to

shaft cracking.

A-4

These papers recommend using continuous monitoring of the 1X and 2X vectors as a

predictive method to detect significant shaft cracking. The staff requested that the licensee

provide some evidence that vibration monitoring was effective for detecting shaft cracks in RR

pumps similar to the Hope Creek RR pumps. The licensee cited the experience at Grand Gulf

discussed above. The Grand Gulf RR pump shafts are hollow shafts as opposed to the solid

shafts used in the Hope Creek RR pumps. Therefore, the Grand Gulf experience may not be

directly applicable to Hope Creek. The licensee provided additional information which

indicates that cracks in reactor coolant pump shafts were identified at Sequoyah (technical

presentation to NDE Steering Committee by G. Wade, July 12, 2002) and Palo Verde Unit 1

(Palo Verde Nuclear Generating Station Cracked Reactor Coolant Pump Shaft Event, H.

Maxwell, 1996) using vibration monitoring. Although these plants are Pressurized Water

Reactors (PWRs), the reactor coolant pumps have solid shafts. The licensee indicated that

these pumps had operated for a significant period of time after the first indication of shaft

cracks by vibration monitoring. A staff review also identified that vibration monitoring

successfully identified a reactor coolant pump shaft cracking at St. Lucie Unit 2 (LER Number:

1993-005). The PWR reactor coolant pump experience provides some indication that a solid

pump shaft will provide better early crack detection capability than the hollow pump shafts,

such as those used at Grand Gulf. PSEG has provided data which demonstrates that shaft

cracks in pump shafts similar to those used at Hope Creek have been detected at other

facilities, and that these cracks were detected in time for operators to take appropriate

actions.

On the basis of the available operating experience, the staff concludes that continuous

monitoring of the 1X and 2X amplitudes and phase angles provides reasonable assurance

that circumferential shaft cracking can be detected with sufficient time for the plant operators

to take appropriate actions. The licensee will either reduce the RR pump speed or remove

the pump from service if the monitoring system detects vibration levels that exceed the limits

specified in the vibration monitoring plan.

The staff also reviewed the licensee’s assessment of the potential consequences of a RR

pump shaft failure. The RR pump shaft axial cracking that has been reported occurred below

the seal area and above the pump hydrostatic bearing. This is the region where a potential

RR pump shaft failure would be expected to occur. The pump impeller would be expected to

settle at the bottom of the pump casing, which could potentially result in some damage to the

pump casing. The unsupported end of the upper part of a broken shaft may damage the shaft

seal. A seal failure would result in leakage of reactor coolant through clearances around the

upper half of the broken pump shaft. This leakage would be bounded by the design basis

small LOCA event. If such an event were to occur, the licensee would be able to isolate the

pump using the RR loop isolation valves, thereby terminating any reactor coolant system

leakage.

Conclusion

The staff concludes that the licensee’s continuous monitoring program for the Hope Creek RR

pumps, as discussed above, provides reasonable assurance that a potential crack in the RR

pump shaft can be detected in time for operators to take appropriate actions to reduce the

pump speed or remove the RR pump from service prior to a complete shaft failure.

B-1

Enclosure 2

High Pressure Coolant Injection (HPCI) Exhaust Line Review






















 

ANO: One dead and Eight Injuried, and only a Yellow Finding.

In the end, I think it was a malicious and intentional ends of Entergy to not follow safety standards and plant procedures based on profits leading to massive plant damage and death and injury to the on site employees!!!

See, the difference between me and the NRC, the real risk or danger to the public…I would measure what the control room staff didn’t know about the heavy lift situational awareness from the moment the heavy lift began till until after all the accident investigation were complete. I would base the magitude of the punishment or incentive  on what the staff didn't know, not on the risk of fuel damage. Fuel damage or potential off site releases are always looking at the "dead body" in the middle of the road through the rear view mirror that you just ran over.

“The results are somewhat less severe than the combination of a red and a yellow finding the regulator initially proposed

The totality of what their actions were going to unleash about the condition of the facility in which they don’t know or understand…

It is setting in motions events and not knowing accurately how it will play out…the gap of knowledge and understanding…

In the end,  I think it was a malicious and intentional ends of Entergy to not follow safety standards and plant procedures based on profit leading to massive plant damages and death and injury to the on site employees!!!

Now you need to start firing the NRC leadership in Region IV  and up to and including the EDO…

But as we see in the VA debacle management people never get fired in government!

I got the NRC plan...they are going to severely increased oversight of the plant. Say the final determination comes at the two year point after the accident. They are going to say we couldn't begin punishs them with drastically increasing inspections because they were in the investigation phrase until after the final determination is in. At the two year point, the NRC going say we are going severely increase inspection for two year beginning at the point of the accident. Thus because two years has passed, they behaved well, we are now going to inspect them on a normal bases.

This was maliciously reckless with the NRC  with not immediately tagging Entergy as an extremely dangerous plant withinj hours of the accident and making the local inspectors assume the site and its staff are dangerous.

You know how this is going to plays out…basically because of all the corrective actions mostly the public can’t see, they won’t much make them pay a price and increase oversight based on the corrective actions and management being such heroes post accident. It is nuclear industry schizophrenia circular rationalizations…

"The NRC inspected the Arkansas Nuclear One plant immediately after the accident and said it had no safety concerns about the plant. However, after a follow-up inspection this February, it determined a "high safety significance" finding related to the accident for unit 1 and one with "substantial safety significance" for unit 2."

You know. I rob a bank with a gun, but awaiting trail and on bail…I don’t deserve any jail time because of all the time I worked at soup kitchens and homeless shelter the judge said.  

Basically this is the NRC corruptly portraying they are punishing a dangerous nuclear plant without actually really punishing them…

Remember the staff wanted one red and a yellow finding. Entergy thought if I asked for two white findings the NRC will split the difference. Thus it became.  Even by asking for the white finding, they admitted they didn’t take the nuclear accident, deaths and injury seriously.

This is the risk regulation game, stick it in a unscrutinizable black block, razzmatazz us, then the NRC can arbitrarily chose the punishment to their brothers and our friends without a wit of public understanding. Leave it to the nuclear gods behind doors to deside our fates.

NRC Issues Two Yellow Findings to Arkansas Nuclear One
The Nuclear Regulatory Commission has determined that two inspection findings at the Arkansas Nuclear One facility in Russellville, Ark., issued in connection with a 2013 heavy equipment handling incident are "yellow," or of substantial safety significance. The plant is operated by Entergy Operations, Inc.
The NRC evaluates regulatory performance at commercial nuclear plants with a color-coded process that classifies inspection findings as green, white, yellow or red in order of increasing safety significance.
Workers were moving a 525-ton component out of the plant’s turbine building during a maintenance activity when a temporary lifting assembly collapsed on March 31, 2013, causing the component to fall, damaging plant equipment, killing one person and injuring eight others. Unit 1 was in a refueling outage at the time, with all of the fuel still in the reactor vessel, safely cooled. Entergy officials declared a Notice of Unusual Event, the lowest of four emergency classifications used by the NRC, because the incident caused a small explosion inside electrical cabinets. The damaged equipment caused a loss of off-site power. Emergency diesel generators were relied upon for six days to supply power to cooling systems.
The falling turbine component damaged electrical cables and equipment needed to route power from an alternate AC power source to key plant systems at both units. This condition increased risk to the plant because alternate means of providing electrical power to key safety-related systems was not available using installed plant equipment in the event the diesels failed.
Unit 2, which was operating at full power, automatically shut down when a reactor coolant pump tripped due to vibrations caused by the heavy component hitting the turbine building floor when it fell. Unit 2 never completely lost off-site power, and means existed to provide emergency power using the diesel generators.
NRC Resident Inspectors responded to the site the day the incident occurred. The NRC conducted an Augmented Team Inspection, prepared a detailed chronology of the event, evaluated the adequacy of licensee actions in response to the incident, and assessed the factors which may have contributed to the incident. Worker safety issues are the responsibility of the Occupational Safety and Health Administration, which conducted an independent inspection of the incident. The NRC determined that the lifting assembly collapse resulted from the licensee’s failure to adequately review Page | 2
the assembly design and ensure an appropriate load test in accordance with its procedures or approved standards.
The Augmented Team Inspection report documented information gathered from the initial inspection and identified areas for further inspection follow-up. The NRC held a public meeting in Russellville on May 9, 2013, to discuss the team’s findings.
From its follow-up inspections, the NRC identified the preliminary red and yellow findings documented in a March 24 inspection report. NRC held a regulatory conference with Entergy officials on May 1, and after considering information provided by the licensee determined that yellow findings were appropriate to characterize the risk significance of the event for both Unit 1 and 2.
The NRC will determine the appropriate level of agency oversight and notify Entergy officials of the decision in a separate letter.