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.  

Employee Sabotage at Millstone Plant and the Happy Talk of Everyone

June 28: Honestly, if a investigation of this nature was ongoing, would they admit it to me?

June 27: An aid to the region 1 administrator called me this morning. They threw my complaint into allegation, I didn't request that. Now it may interfere with my worthless 2.206. He said I didn't have enough evidence to throw it into a deeper or more immediate investigation. He asked me if I had more information and I told him that is a area I can't get into. I heard his little fingers tapping on his computer keyboard all though this conversation...so this is in official documents. All I was trying to do is raise NRC awareness through multiply channels and get it documented. I consider this a success. I warned this aid that the public might see this through a different lens than the agency’s policies and procedures.

I am in a process of continually updating this blog and polishing it. This is definitely going into a 2.206 process with my intent to get this onto the official record. 

 June 24@1130am   Ok, so I want to talk multiple pathways into the NRC. I called the region 1 top administrator Bill Dean’s office. At best, I wanted to get a short recording on his phone. I got to the secretary, couldn’t leave a message, then wanted me to talk to one of his aid, wasn’t available. Finally she connected me to enforcement. I asked her to sum up our discussion, then give it to Bill. I told her I neither trust enforcement or the allegation department…the excuse to stick it in a secretive investigation and then make it disappeared.  

June 24@9:30am Talked to the senior resident. It is basically a simple shrink tube like rubber material they slide over a cable connection for environmental conditions. Just like the pictures below. Those ty wraps and the plastic bag were slipped inside the Raychem boot around the cable and intentionally they shrunk the boot around the foreign material. Well, the resident didn’t say it was malicious, as they haven’t have looked over it yet. She said she would be making a note about I think it is malicious.

She said this won’t be inspected until the third quarter of this year and I (me) am guessing we won’t see the results until Feb 2015…

I told her you are our heroes and thanked her for the hard work. Told her, “you are dealing with an encyclopedia worth of weak and useless rules that make you powerless to control the behavior of a plant like this.” Your nation doesn’t give you enough power, where a giant corporation like this has any fear of you at all. Dominion can falsify nuclear safety documents at will and they have absolutely no fear they will be held accountable in any meaningful way. Our nation as yet, doesn’t give them any meaningful incentive to want to change their bad and corrupt behavior.  

I am astonished this inspector's alarm bells aren’t going off big time…they are falsifying federal documents. What if all their documents submitted to the NRC are falsified or maliciously incomplete???

"foreign material (ty-wraps and a plastic bag) were found inside the cable environmental seal (Raychem boot) of the 'A' phase"

June 22@3:30pm: I put a call into the Millstone residents and left a message for them to call me on this LER.

Are they talking about the inside metal electrical box with the foreign material? 

 

This guy is a mess:

1) Feb 3:repeated issues with unit 3's  turbine- driven auxiliary feedwater pump and special inspection
 

2) May 25: trip of both units due with some kind of relay problem in the switch yard and failure of unit 3's non safety instrument air and another special inspection...

Unit 3 issues with turbine- driven auxiliary feedwater pump during the LOOP event.
 

3) inoperability of Unit 2's turbine- driven auxiliary feedwater pump for fourteen years due ty-wraps and a plastic bag foreign materials. Was that materials part of the work done on 2000. Say, was the plastic bag holding parts that went into the job...was the ty wraps actually going to the 2000 job?

Event date: April 10, 2014      

Report date: June 9, 2014

This employee gets a thrill out of secretly damaging nuclear safety equipment and taking a chance…a thrill game…with breaking a host of company rules. 

We don't know what kind of plastic bag it was and was their illegal drug residue inside the bag??? I can't believe the ty wraps would have anything to do with this Job.

LER 2014-004-00 (Unit 2)

DOMINION NUCLEAR CONNECTICUT, INC. MILLSTONE POWER STATION UNIT 2 LICENSEE EVENT REPORT 2014-004-00 FOREIGN MATERIAL FOUND IN A MOTOR LEAD RENDERED A MOTOR DRIVEN AUXILIARY FEEDWATER PUMP INOPERABLE
 On April 10, 2014, with Millstone Power Station Unit 2 in MODE 6 at 0% reactor power, while de-terminating the motor leads for the 'B' Motor Driven Auxiliary Feedwater (MDAFW) Pump motor, foreign material (ty-wraps and a plastic bag) were found inside the cable environmental seal (Raychem boot) of the 'A' phase. An inspection of the electrical motor leads revealed no damage occurred. This motor was last re-terminated In May 2000. The motor leads to the other phases did not have any foreign material inside the Raychem boot. Since the Raychem boot was not in the as tested environmentally qualified (EQ) configuration the 'B' MDAFW pump was considered inoperable. The direct cause was an historical inappropriate maintenance practice which rendered the MDAFW pump inoperable. Plant Technical Specifications (TS) 3.7.2.1 Action d, states in part, that in operating MODES 1, 2, or 3, with two AFW pumps inoperable, the plant must be in at least HOT STANDBY within six hours and in HOT SHUTDOWN within the following 12 hours. A review of the control room logs for the past three years determined there were 4 occasions where there were two AFW pumps inoperable for longer than allowed by TS.

The 'A' phase motor lead was properly re-terminated. During the most recent MPS2 refueling outage (spring 2014) in april or after.

 

In the above, we don’t know how bad the situation is because the rules say you need only report events (4) back three years, while the employee sabotage and the beginning of the safety component inoperability occurred fourteen years ago. You know, the rule say, if you kill a guy and don't get caught for 3 years, the courts can't prosecute you? The rules are set up where where if you got ten drunken driving convictions in 15 years and killed three people, but now the courts and newspapers can only look back 4 years where you only have one DUI conviction. Who creates such unfair rules for the public...why and who do these rules serve? Do you for one second believe the public would vote for this of game...they would find it acceptable? I got a solution for this, be diligent and don't break the rules creating such a horrible record.  

Basically this is a Raychem electrical cable boot or rubber covering. They heat it up and it shrinks to a leak proof shape around the electric cable. It sounds like the employee stuck the ty wraps and plastic bag inside the rubber seal. It can't be a simple oversight, somebody kicked the wrench in the hole unseen and by mistake...

This had to be malicious and with intent!!!

What is a ty wrap?

I believe it is these guys?

Ty wraps;




I am saying, you can create a set of so called legal rules and laws where your behavior is portrayed to outsiders much better than what has actual happened. The record is inaccurate and it is portrayed to outsiders much better than what you really earned. Nothing more damages a safety culture than this. It is like a child with his report card changing his "D" grades into a "A"s before the parent sees the report cards.  

In a six months period, the NRC reported a host of so called low level events where the plant staff looked at problems shallowly. Dominion always gain a benefit from this cheating, where they repeatedly use their errant bad judgement in a way that favors not spending money and drives the plant to be less conservative than the public would expect out of Dominion. Do you ever see them make a bad or inaccurate judgement where it drives them to be more conservative or cause them to wast money?   

Inspection Report 2014002

Unit 3

Description. On February 23, Dominion performed post-maintenance testing on the ‘A’ SW pump and the pump did not meet its acceptance criteria. The acceptance criteria included the requirement for running amps to be less than or equal to 84.1 amps and the results at the three testing positions were 85, 82, and 85 amps. The 84.1 amp value is the nameplate current value listed on the motor. Operations consulted the engineering department for assistance in disposition of the results and engineering concurred that the acceptance criteria could be changed to 85 amps and the ‘A’ SW pump returned to an operable state. Engineering concluded that exceeding the motor nameplate current by 0.9 amps would not result in any significant short term motor degradation. Based on engineering’s assessment, operations changed the acceptance criteria to 85 amps and declared the ‘A’ SW pump functional.

The inspectors questioned the basis of this assertion, because the service factor of the ‘A’ SW pump is 1.0, which would imply that even a small increase in amperage could have adverse consequences to the motor. Dominion generated a CR with the inspector’s concerns (CR541081) and upon further investigation found that they had not considered whether the motor will start/accelerate as designed during a degraded bus voltage consideration or what impact there would be on the bus if the motor is running and the station encounters a degraded bus voltage condition. Dominion operators placed the pump in a pull to lock condition and entered Technical Requirements Manual 3.7.4 for having one SW pump non-functional.

The inspectors questioned the basis of this assertion, because the service factor of the ‘A’ SW pump is 1.0, which would imply that even a small increase in amperage could have adverse consequences to the motor. Dominion generated a CR with the inspector’s concerns (CR541081) and upon further investigation found that they had not considered whether the motor will start/accelerate as designed during a degraded bus voltage consideration or what impact there would be on the bus if the motor is running and the station encounters a degraded bus voltage condition. Dominion operators placed the pump in a pull to lock condition and entered Technical Requirements Manual 3.7.4 for having one SW pump non-functional.

Specifically, Dominion had not tracked, trended, or reviewed the performance of the installed cards that had been repaired with NSR parts. Based on interviews, the inspectors determined that Dominion assumed none of the repaired cards had failed, because the overall failure rate of all 7300 cards was believed to be very, very low. Contrary to Dominion's assumed failure rate for cards with NSR parts, the inspectors identified two instances of repaired cards which had been returned to NAPS for additional repairs after an in-service period of a few years. Therefore, the inspectors concluded that Dominion's assessments were based, in part, on an unverified assumption regarding the failure rate of cards repaired at NAPS because the performance history (e.g., failure rate) of the installed affected cards was not fully understood.

 

If they never pay a price for bad behavior, how do you ever expect them to change and evolve in a positive way? The moral hazard. The two special inspections and the erratic operation of the TDAFW leading to the potential of confusing the control room operators in a serous accident. How pathetic and powerless is the NRC, where they can't make them fix this core cooling safety pump at the first opportunity. How pathetic weak and powerless is the agency in doing our greater good. 

The is the Veteran Administration in the nuclear industry!!!    

On January 23, 2014, the Unit 3 TDAFW pump failed a required surveillance test. During the starting sequence, the pump tripped on overspeed due to mechanical binding in the turbine governor linkage. Dominion entered TS LCO 3.7.1.2(a) action (C) which provided up to 72 hours to repair the failed pump before requiring Unit 3 to be shutdown to Mode 3. Troubleshooting efforts revealed that the mechanical linkage between the governor and the turbine control valve (3MSS*MCV5) was binding due to a degraded cam follower bearing and a mechanical link that had been installed incorrectly. Although repairs had been completed, it became apparent thatthe required post-maintenance tests, including a full flow test at full power, could not be completed prior to the expiration of the LCO on January 26, 2014. Dominion requested enforcement discretion from compliance with TS 3.7.1.2 for a period of 72 hours. The NRC reviewed the request in accordance with IMC 0410, NOED, and granted a one-time 48 hour extension to required action (C) of TS LCO 3.7.1.2(a).Dominion completed the post-maintenance testing and restored the TDAFW pump to an operable status within the additional time granted.

Obviously, the NRC's ROP is not reporting to the community in a way portraying the full and accurate dangerous condition this site is in. We aren't fairly giving the public the opportunity and incentive to change Millstone and Dominion. The NRC just doesn't have enough horsepower to make these guys change and become better corporate citizens. The dangerous conditions I am talking about is, a nuclear accident or the plant being operated in such unreliable manner as a third world country's puppet regime would be ashamed to have them operating in their country. 

Need I remind everyone the NE grid is in a terrible crisis without sufficient power capacity this summer and into the foreseeable future. You say boo in this condition, the cost of grid electricity doubles or triples.

05000423/2013005: Introduction. The inspectors identified a Green Finding (FIN) for the failure to follow Dominion Procedure OP-AA-102, “Operability Determinations,” and establish adequate compensatory measures to restore reliability to the Unit 3 TDAFW following an overspeed trip on November 4, 2013. Subsequently, the TDAFW pump tripped again on overspeed during surveillance testing on December 18, 2013.

Discussion. The TDAFW pump tripped on overspeed on November 4, 2013 and December 18, 2013, during scheduled surveillance testing. Dominion attributed the initial test failure to condensate in the steam lines without fully evaluating other potential causes that could contribute to the failure to start. As a result, the reliability of theTDAFW to respond to a start signal was reduced. Compensatory measures established following the November 4 test failure and subsequent revisions to the prompt operability determination were inadequate and did not prevent the December 18 failure. Additional compensatory measures were subsequently added.

In August 2013, Dominion adjusted the governor compensator on the TDAFW pump such that the speed sensitivity of governor was reduced in order to prevent spontaneous oscillations from occurring at low flow rates. Subsequently, on November 4, 2013, the TDAFW pump tripped on overspeed during the start sequence during a quarterly surveillance test. A prompt operability determination (OD000561, Revision 0) assessed the cause of the trip as being due to a buildup of condensate in the steam supply lines to the TDAFW pump. Compensatory measures were established to eliminate the source of the condensate by ensuring the steam traps were adequately draining the steam supply lines. The operability determination attributed the probable cause of the overspeed trip as being caused by the failure to properly operate and maintain the steam traps in the steam lines such that condensate accumulated in the steam lines and caused the throttle valve to fail to close due to hydraulic drag. On November 5, the ‘D’ steam line isolation valve to the TDAFW pump was closed. The ‘D’ steam supply line remained isolated until December 18, 2013.

Dominion Engineering considered several other potential causes in the analysis in OD000561, Revision 0, but determined that they were likely not involved in the overspeed trip that occurred on November 4. Subsequent revisions to the initial operability determination (Revisions 1 and 2) provided further rationale to justify why governor and throttle valve potential failure modes did not require compensatory measures to restore reliability. As a result, Dominion did not conduct any further testing of the governor, the governor linkage and the throttle valve, 3MSS*HCV5, nor did they establish compensatory measures that would have addressed these other potential causes. On December 5, CR534403 identified that “there was a discreet (vs. smooth) change in the acceleration rate” of the TDAFW pump during pump startup that had not been observed prior to the maintenance on the governor in August. A timely recommendation by the root cause team to test the throttle valve and governor for binding prior to the next scheduled surveillance test was not implemented prior to the second overspeed test failure on December 18.

OD000561 (Revisions 0, 1, and 2) was narrowly focused on the malfunctioning of the steam traps as the source of the condensate building up in the steam lines. On December 18, Dominion unisolated the ‘D’ steam supply line and another overspeed trip subsequently occurred during the surveillance test. The root cause evaluation was still in progress and the causal assessment had not been fully completed when operations restored the ‘D’ steam line to service in preparation for the surveillance test.  

Dominion focused on the malfunctioning steam traps upstream of the steam admission valves as the primary cause of the test failures requiring compensatory measures. The other potential causes of the problem were not fully investigated. They did not use conservative assumptions in the decision making process and did not demonstrate that the other potential causes were not valid when formulating compensatory measures to restore reliability. Dominion did not fully investigate nor recognize that condensate was trapped in the steam line between 3MSS*AOV31D and 3MSS*MOV17D (downstream of the steam admission valve) which may have caused or contributed to the turbine overspeed condition. They also did not further investigate possible degradation of the governor, linkage, nor throttle valve binding as potential causes.

The Palisades PCP Impeller Continues!

June 26:

According the NRC tonight Entergy replaced the C PCP pump with a new one this outage and a malfunctioning PCP seal on the new C pump caused the most recent shutdown.

It was a new seal!! 

June 22: 

Hmm, the Cooper plant secretly just came down for a recirc pump seal job a week or so ago. Had to pry it out of them.  One is PWR and the other is a BWR. It is suspicious though as hell…are they related?

Is there some deep management philosophy thing going on...like just let it run till it fails. Did they take a shutdown with anomalies readings on the seal…just start up without replacing the seal because they didn’t have enough time?  

See bottom update...








+++The Below is the first entry setting this up and then Reposted from 6/20...everything else was added after one day later.

Junk and obsolete "primary coolant pumps" and Entergy has a habit of intentionally running safety equipment until failure. We have no idea if the proper maintenance was taken on these seals...

Maybe they will break another impeller blade on the way down and up...they will be running these pumps outside their design margins during the shutdown and start-up. Everyone cross their fingers!

June 26: The severely out of balanced  impeller since 2011 damaged the C pump...this cause them to replace the whole unit this spring. The brand new pump and its brand new seals failed upon start-up...this is what caused their new shutdown.  

Was it the pump they dissembled looking for blade damage this outage?

"2014: The licensee removed the impeller from PCP-C and replaced it with a newly manufactured impeller. The removed impeller had missing portions in two impeller vanes." 

Obviously the massive vibrations with the severely out of balance impeller shortened the life of the seals? You think Entergy would be smart enough to replace the seals at the same time...I doubt it.

Now when did they come out of their recent outage...March 16.

Congratulation Entergy on that record run of 97 days!  

(June 22: Pretty cool ha, sending signals...)

COVERT TOWNSHIP, MI – Palisades Nuclear Power Plant was removed from service at 11:30 p.m. Friday, (June 20).

 You catch that...I put this up on the internet at 4 pm yesterday:)

That is being done to conduct a "planned maintenance outage" to replace a primary coolant pump seal, says Lindsay Rose, spokeswoman for Entergy Corp., which owns Palisades.
She said the outage will be brief but she would not provide an estimate of how long, saying that is not information the company makes available to the public.
"This is not an emergency situation at all," Rose said. "We are just shutting down to replace this now so we can have more reliable operations in July and August, through the summer, when energy demand is higher."
She said the seal helps maintain pressure inside one of four primary coolant pumps at the plant.
"There are primary pumps that push water from steam generators to our reactor vessel," Rose said. "We have four of them. We are replacing the seal in one of the pumps."
She said the seal is being replaced "because we've been monitoring the seals and we noticed one of the seal's layers – each has four layers – and we've noticed one of the layers of the one seal wasn't performing the way it should."
The pumps work together to circulate water and keep the vessel cool.
Early this month, Allison M. Macfarlane, chairwoman of the U.S. Nuclear Regulatory Commission, and U.S. Rep. Fred Upton, R-St. Joseph, toured the plant to see safety upgrades. They said the plant was safe but Macfarlane acknowledged that there were concerns about a "chilled work environment" in Palisades' security department.
In a poll, workers said they believed they could not raise safety issues without facing retaliation.
Macfarlane said there was no final word on what the NRC would do to address those concerns, "but it's something we look at very seriously."

These reports are so selective and incomplete…no mention in the 2012 inspection report and I believe the newest IR don't mention "out of licensing" issue began in 2002. I don’t trust these guys to give us the unvarnished truth on these events.

I can’t find the non sighted violation so far... 

 05000255/2012003

In further consultation with industry specialists over the next several months, the licensee reviewed previous site and industry operating experience regarding PCP impeller issues and assessed the manner in which the Palisades pumps were operated. The research concluded that the cause of the failures is fatigue-related effects from the operation of the pumps in conditions beyond the maximum flow rates and below the minimum net positive suction head recommendations as described in the UFSAR and other design documentation.

In response to the October 2011 event and subsequent research conducted to better understand the phenomena affecting the PCPs, the licensee has instituted a monitoring plan, changed the preferred sequence for starting/stopping PCPs during startups and shutdowns, and has corrective actions to explore further procedure changes regarding operation of the PCPs and the resultant impact on other aspects of plant operation. 

 

This is a brand new inspection report.

I just can't understand this, yet this continuation of allowing the operating the PCP outside the design operating critera in 2002 lead to the distruction of many PCP impellers.

I can't find any non sited violation of the PCP pumps in 2002...somebody is smoking dope in the NRC. The idiot must be must be talking about 2012.  

June 20:

PALISADES NUCLEAR PLANT – NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000255/2014007

For example, the licensee received a non-cited violation in 2002 for the failure to operate the primary coolant pumps in accordance with their design operating criteria. The inspectors verified that the licensee’s evaluations for the issue were comprehensive and the corrective actions completed and planned were appropriate and timely, commensurate with their safety significance.

 

This is the first time I’d seen this…

Was this in the recent inspection (foreign material) about this?

June 21@ 6:30pm

>>>>Can you even imagine how many well educated NRC officials looked over IR 2014007 for errors? So I looked in the back section of the "listed of documents" they inspected. They had no 2002 documents listed in this inspection report. This below is what they looked at.

We are lucky these guys aren't reactor operators.The NRC looked over IR 2012003 and recertified there was no any operational safety issues with repeatedly spewing RCP impeller blades all in the coolant over the decades. But we could never see the secret internal document...how do we know the operational determination was thorough?<<<<    

CR-PLP-2012-02044 Operation of Primary Coolant Pumps with Inadequate Net Positive Suction Head April 2, 2012