WSJ: New York State Calls for Tougher Inspections at Indian Point

I bet you it is in the purchase specification of the transformer...getting a cheaper grade of transformer.

We got a national security issue with this. Most of the USA’s transformers are made outside the USA.

What country did this failed transformer come from?

You got some corporate financial pinhead with no idea how a nuclear plant works dictating the quality of the transformer through price and specification. 

Has the Plant transformer fire led to an intensification of the pissing match between Entergy and the state of new York?    

WSJ: New York State Calls for Tougher Inspections at Indian Point

By Joseph De AvilaUpdated May 20, 2015 2:55 p.m. ET 

New York state is renewing its call for tougher oversight of electrical transformers at the Indian Point Energy Center after the third failure in eight years of one of the power-transfer devices at the nuclear plant.

A transformer for Indian Point’s unit 3 exploded and caught fire May 9 in the nonnuclear section of the power plant 30 miles north of New York City. No one was hurt and no other equipment damaged.

The state’s call for more intensive inspections comes as Entergy Corp.ETR-0.05%, the owner of Indian Point, seeks to renew its operating licenses for units 2 and 3 with the federal Nuclear Regulatory Commission. The state has opposed the renewal.

During relicensing proceedings, the state has argued that Indian Point’s transformers should be subject to what is known as an aging-management program as a condition of the facility being re-licensed. Such programs apply to so-called passive components, such as those with no moving parts, and are inspected periodically for degradation due to aging.

The NRC, however, classifies transformers as so-called active components, subject to a different set of inspection rules.

A regulatory tribunal agreed in 2013 with New York state’s position. But that ruling was overturned in March by the NRC.

“As the history of explosions and fires at Indian Point make clear, transformers play an important role in nuclear plant safety,” said New York state’s Attorney General Eric Schneiderman, whose office has represented the state in Indian Point’s re-licensing process. “The time has come to require that transformers be closely and frequently monitored as a part of the facility’s aging management program as I have raised in the re-licensing proceeding.” 

The NRC is scheduled to hold a public meeting Wednesday in Tarrytown, N.Y. on its assessment of Indian Point’s safety performance in 2014. The assessment, issued in March, found that Indian Point “met all cornerstone objectives” and wouldn't be subject to additional inspections above and beyond normal reviews.

Jerry Nappi, a spokesman for Entergy, said both of unit 3’s transformers passed extensive electrical inspections in March. Transformers at Indian Point get these intensive inspections every two years. Aspects of the devices also are inspected daily. 

“Everything that can be done using best industry guidance to monitor transformers was done,” he said. “Three transformers in less than 10 years is unusual. We need to get to the bottom of that.”

NRC officials say that main transformers at nuclear power plants are subject to ongoing monitoring, inspection and testing programs that serve the same purpose as an aging management program. “There is no evidence at this point to support the idea that placing the transformer under an aging management program would have resulted in a different outcome,” said Neil Sheehan, an NRC spokesman. “All of that said, our inspections of the transformer failure event are continuing.” 

Mr. Sheehan said the commission hadn’t determined whether the May 9 transformer failure would warrant additional oversight at Indian Point’s unit 3 reactor. 

The NRC also announced Tuesday it had begun a special inspection at Indian Point to look into the presence of water in an electrical-supply room that had equipment that provided power to safety systems at the plant. Entergy officials said that water from the sprinkler system flows into this electrical-supply room into a floor drain by design. After the fire, the water didn't drain as quickly as expected, they said. 

Some 16,000 gallons of transformer oil called dielectric fluid is still unaccounted for after the fire, according to Entergy. An unknown amount of that oil spilled into the nearby Hudson River. Dielectric fluid is a light mineral oil used as an electrical insulator and coolant for transformers.

The transformer that failed earlier this month replaced another transformer that malfunctioned and caught fire in 2007. Another transformer failed in 2010, which had been in operation for four years.

“I find it very difficult to understand with the high number of failures that they have experienced at this site, that Entergy hasn’t taken the political bull by the horns and set up a monitoring procedure, which no one can argue with,” said Robert Degeneff, an engineer and consultant in transformer performance.Mr. Degeneff, who testified for the New York Attorney General’s office during relicensing proceedings, said the company also should develop monitoring procedures with an independent third party.

Over the past 40 years, there have been at least 85 transformer fires at U.S. nuclear power-plant facilities, according to records from Dave Lochbaum, director of the Nuclear Safety Project at the Union of Concerned Scientists.

Mr. Lochbaum said nuclear plants generally don’t inspect their transformers monthly basis because transformers don’t tend to degrade that quickly.

“I think [Entergy] will look at what they were inspecting and how they were inspecting rather than frequency,” Mr. Lochbaum said. “When they lose that transformer they also stop making revenue. They have a huge incentive to get a reliable transformer.”

Indian Point Needs New Yard Loop Fire System and Distribution Piping

Update May 20: 

The NRC is worrying about the poor attitude reflecting the care of the fire water system at the facility?

May 4, 2015: SUBJECT:REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE INDIAN POINT NUCLEARGENERATING UNIT NOS. 2 AND 3, LICENSE RENEWAL APPLICATION, SET 2015–01 (TACNOS. MD5407 AND MD5408)

RAI 3.0.3–5 

Background 

The response to RAI 3.0.3 1 dated December 16, 2014, states that the fire protection water and city water systems have experienced recurring internal corrosion (RIC), as defined in LR-ISG- 2012-02. With regard to the fire protection water system, the response states, “[l]ocalized corrosion has resulted in minor through-wall leaks that have no impact on system performance and do not threaten the structural integrity of the piping or the safety function of nearby equipment.” No changes were proposed to the Fire Water System Program to address RIC.
With regard to the city water system, the response states, “[h]owever, based on past operating experience, they [through wall leaks] do not compromise the intended functions of these or any other system, and do not warrant aging management program activities beyond those provided by established aging management programs and the corrective action program.” Issue 

Past performance does not provide reasonable assurance that throughout the period of extended operation, internal general corrosion will be revealed by a through-wall leak prior to the general corrosion potentially impacting the structural integrity of the system. Nor does it provide reasonable assurance that larger through-wall flaws sufficient to challenge the pressure boundary function will not occur. It is also unclear to the staff that a sufficient representative sample exists for the carbon steel piping to demonstrate that general corrosion is progressing slowly enough that it will not prevent an in-scope component from performing its current licensing basis intended function during the period of extended operation. Although to date through-wall leaks have not affected the safety function of nearby equipment, the staff lacks sufficient information to conclude with reasonable assurance that this will be the case throughout the period of extended operation. Request 

1) State the basis and justification for concluding that existing inspection data are sufficient to demonstrate that general corrosion is progressing slowly enough that it will not prevent an in-scope component from performing its current licensing basis intended function during the period of extended operation. 2) State the basis and justification for concluding that through-wall leaks will not impact the safety function of nearby equipment throughout the period of extended operation. 3) Provide the staff with sufficient quantitative data for it to reach the same conclusion. Alternatively, propose periodic inspections in response to SRP-LR Section 3.3.2.2.8, “Loss of Material due to Recurring Internal Corrosion.” RAI 3.0.3–13 

Background 

As amended by letter dated December 16, 2014, LRA Sections A.2.1.13 and A.3.1.13 state that the enhancements to the Fire Water System Program will be implemented by December 31, 2019. Issue 

As stated in RAI 3.0.3 12, it is not clear whether an enhancement is necessary to address augmented testing for fire protection water systems that are normally dry but periodically subject to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) that cannot be drained or allow water to collect. SRP LR Table 3.0 1, as amended by LR ISG 2-12 02, states that the augmented testing should commence 5 years prior to the period of extended operation. Given that IP2 is beyond the expiration of its initial license (September 2013) and IP3 will be beyond its initial license period in December 2015, the staff questions why the augmented testing would not commence sooner than December 31, 2019. RequestState and justify the basis for why the augmented testing for fire protection water systems that are normally dry but periodically subject to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) that cannot be drained or allow water to collect will not commence until December 31, 2019

*** guess they mean once they pressurize the fire nozzle by the automatic fire system control valve and they then secure the system...water would stay in the pipes up to the nozzle unless they had a way to drain this water. It would cause corrosion in the pipe and it would freeze in the winter thus blocking off the water to fight the fire. So they have an automatic valve that opens upstream of the main automatic, or it actually it is in the main automatic valve that drains the upstream water down into the sump in the power room. . It sounds like the main valve stayed open while header drain valve was opened for some period of time. One or both of the valve had a maintenance problem.

“The spokesman for Indian Point's owner said water from a sprinkler system flows to a floor drain in the electrical room by design, but did not drain as quickly as expected.” 

They might test the main automatic value on yearly bases or every outage. They actually fake a fire signal...this opens up the main valve pressurizing all the transformer fire water nozzles. It is actually a great show with all the nozzles spraying. This is all documented. Did they know there were issues with main automatic fire system control valve, but didn’t get it fix. Did they have extra water in the sump before in the testing.

Bottom line, it is a terrible place to have a fire system header drain down line into a main electrical room sump...

Just submitted the to the NRC blog, I am pretty controversial talking about Gov Cuomo.   

I think the Independent National Transportation and Safety Board did a wonderful job at explaining the tragic crash of the Amtrak Philadelphia commuter train.  I’d give them an “A” plus.

I do miss NTSB chairperson Deborah Hersman’s pretty face and especially her ability to communicate.  

Hmmm, the NTSB is missing a commissioner just like the NRC? 

As I said earlier, if Indian point and the NRC did a proper 50.59 and License Amendment Request (LAR)...the replacement of nonflammable PCB coolant to flammable vegetable oil coolant...they would have hardened the area around the transformer expecting a big vegetable oil fire and tremendous amounts of fire hose water being used.

Published on May 18 at 12:45 pm: 

"Indian Point Needs New Yard Loop Fire System and Distribution Piping"My guesses are: 

1) A leaking fire water system piping or component.

2) The copious fire hose water leaked down outside of the concrete foundation and then entered though a concrete foundation crack into the power supply room. Are there many concrete foundation cracks in IP buildings?  The fire fighters must have directed copious hose water protecting the turbine building siding. Was there damage to the siding?

3) The building siding was damaged by the fire...that is how the water got into the power room?

4) The overflowing transformer holding tank backed up into the supply room if both connected to each other. Does the supply room have a drain and where does it go? 

Did the NRC shame Gov. Cuomo by not telling him about supply room water on the floor or did the Governor intentionally withhold the water leak in the said electrical room from the public for some reason? Why didn’t the Governor disclose the water on the floor? The information was big deal heading into a special inspection.

Bet you the equipment operator has to inspect that room every four to eight hours.

Mike Mulligan Hinsdale, NH

May 19 2015 at 2 pm: NRC Begins Special Inspection at Indian Point 3 Nuclear Power Plant to Review Issue Associated with Transformer Event on May 9

A team of NRC inspectors will seek to better understand the presence of water in an electrical supply room at the Indian Point 3 nuclear power plant following a main transformer failure event at the site on May 9th.
Starting today (Tuesday, May 19), a three-member NRC Special Inspection Team will report to the Buchanan (Westchester County), N.Y., facility to review the issue. The room in question contains electrical equipment that provides power to plant safety systems.

“None of the electrical equipment became wet or experienced any damage or failures as a result of the water,” NRC Region I Administrator Dan Dorman. “Nevertheless, the NRC inspectors will be tasked with gathering information on how the water accumulated in the room and the potential for impacts had there been a significantly larger volume of water.”

At 5:50 p.m. on May 9th, with the plant operating at 100-percent power, one of its two main transformers experienced a failure, the cause of which is not yet known. The failure resulted in an automatic shutdown of the reactor that occurred without any complications. Plant operators declared an “Unusual Event” -- the lowest of four levels of emergency classification used by the NRC -- at 6:01 p.m. because of the fire that erupted following the transformer failure.

The Unusual Event was terminated at 9:03 p.m. after the fire was fully extinguished.

A fire suppression system for the transformer automatically doused the fire. In addition, the plant’s on-site fire brigade and off-site firefighters sprayed water and foam onto the transformer to help put out the fire. Among other things, the NRC inspectors will be reviewing whether those sources account for the water observed in the electrical equipment room.

A report summarizing the findings of the Special Inspection Team will be issued within 45 days after the conclusion of the inspection.

Indian Point 3 remains offline while work to replace the transformer. 

May 18 at 1245 pm:

Can you imagine a Unit 3 transformer fire and the big system supply pipes fail leading to flooding in other buildings and dry fire stand-pipes in a big fire. think of the media then? 

This site needs to rip all all their corrosion degraded fire system piping and replace with new. The whole site needs new piping and not piecemeal. 

May 12, 2015  INDIAN POINT NUCLEAR GENERATING – NRCINTEGRATED INSPECTION REPORT 05000247/2015001AND 05000286/2015001

Annual Sample: Review of Fire Protection Piping Failure

a. Inspection Scope

The inspectors performed an in-depth review of Entergy’s evaluation and corrective actions associated with through-wall piping leaks and a degraded piping section in the Unit 1 and Unit 2 common fire protection system. The piping section cracked and leaked on December 29, 2014, causing all fire protection pumps to auto-start. Operators stopped all of the pumps for a period of about two hours while isolating the failed piping section.

Entergy documented the piping failure in CR-IP2-2014-6668. The inspectors reviewed earlier CRs such as CR-IP2-2010-5187 and CR-IP2-2008-0044 which were written to document through-wall leaks in the same fire protection pipe section. The inspectors assessed Entergy’s problem identification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of corrective actions to determine whether Entergy was appropriately identifying, characterizing, and correcting problems associated with the degraded piping and whether the planned or completed corrective actions were appropriate, timely, and in accordance with Entergy’s procedural requirements. The inspectors compared the actions taken to the requirements of Entergy’s CAP, FPP plan, and operating license. In addition, the inspectors reviewed subsequent testing, performed field walkdowns, and interviewed engineering personnel to assess the effectiveness of the corrective actions.

Introduction: A self-revealing Green NCV of license condition 2.K. was identified when Entergy failed to take adequate corrective actions for degraded fire protection piping following leaks identified as early as 2008. These earlier leaks contributed to a large piping leak in a 10-inch fire protection line which required operators to secure all high pressure fire pumps until the affected section could be isolated.

Description: On December 29, 2014, plant operators received alarms for low pressure on the fire header and observed a start of all three fire pumps due to low fire system pressure. The low pressure was caused by an axial split in a 10-inch diameter fire protection piping spool piece. After verification that no fire existed, operators turned off both motor-driven fire main booster

Entergy's Business Philosophy Beating The Hell Out Of Pilgrim..

So basically obsolete and poorly designed equipment beating the hell of of the plant, the switchard gear, main condenser tubes and SRV valves.

A host of  preventable scams, shutdowns and  down powers continue to plague this plant. This damages equipment and risk of a much more significant accident.  

May 11, 2015

PILGRIM NUCLEAR POWERSTATION – NRC INSPECTION REPORT 05000293/2015001 AND INDEPENDENT SPENT FUELSTORAGE INSTALLATION (ISFSI) REPORT 07201044/2015001

Summary of Plant Status

PNPS began the inspection period at 100 percent power. On January 27, 2015, during a severe winter storm, operators reduced reactor power to 52 percent due to degrading switchyard conditions when an automatic reactor scram occurred with the loss of 345 kilovolt (kV) offsite electrical power sources (line 355 and line 342). The operators took the unit to cold shutdown that same day and remained in that condition for restoration of the 345kV offsite electrical power sources, replacement of

So they replace the 3A and 3C SRV values. They only admitted one was broken, These new safety valves within weeks of first startup in 2011 began to leak and since have been plagued with premature degradation, leaks and failures. I solely blame the NRC for not using their so called big hammer to enforce safety reliability issues.  

the 3A and 3C safety relief valves (SRVs), and repairs to the Y2 vital instrument bus. Operators commenced a

This is the first time we hear this, they had some damage on the Y2 vital "instrument" bus. The storm and the shutdown damaged the vital instrument bus. Just saying, the NRC and Entergy doesn't disclose all the safety problems on a event, they slowly leak it out for months knowing everyone is sleeping.   

reactor startup on February 6, 2015, and returned the unit to 100 percent power on February 8, 2015. Operators reduced reactor power to 55 percent on February 9, 2015, to perform a rod pattern exchange, and returned to 100 percent power that same day. On February 14, 2015, the operators performed a controlled shutdown and proceeded to cold shutdown based on procedural requirements during blizzard conditions. Operators performed a reactor startup on February 17, 2015. On February 18, 2015, after achieving 20 percent power, troubleshooting of the main

Well never know how many down power and shutdown there will be in the future with a degraded condenser. Remember all those down powers and shutdowns over Fitzpatrick's leaking main condenser tubes until they replace them all. I think for reliability of the NE grid Pilgrim needs a new main condenser or extra glue.

condenser was performed due to condenser tube leaks. Following repair of the condenser tube leaks, operators proceeded with power ascension on February 19, 2015. Operators returned the unit to 100 percent power on February 20, 2015. On February 21, 2015, operators reduced reactor power to 60 percent to perform a rod pattern adjustment. Operators returned the unit to 100 percent the same day. On March 18, 2015, operators reduced power to 70 percent to perform a rod pattern adjustment. The unit was returned to 100 percent power the same day and remained at 100 percent power for the remainder of the inspection period.

Did they think the "A" degraded or weak...didn't want to use it? Usually they cycle using all the remain operating valves?

3B and 3D SRV continued use after 3C SRV

Description. 4160V undervoltage relays 127-509/1 & 2 are designed to provide an alarm to the control room operators in the event of an undervoltage and overvoltage condition on 4160V safety-related electrical bus A5. In 1989, problem report PR-1989-2244 was issued regarding a degraded voltage scenario that was identified from operating experience at other boiling water reactors (BWRs). The scenario specifically looked at the potential for a voltage regulator failure of the operating EDG during a simultaneous LOOP and LOCA. Given that the LPCI valves are powered from 480V electrical bus B6, which receives power from 4160V Bus A5 and A6, a failure of the EDG voltage regulator during a LOOP/LOCA would cause the LPCI valves to fail to open or fail in place and not fully open. This would prevent the ECCS from injecting at low pressures and potentially lead to core damage. The corrective action to this scenario included two parts that were implemented at different times. First, in 1989, to ensure this event did not impact the ECCS injection

I wonder how often the shift practice this kind of failure. I basically call the shift in a Cat 4 complexity hurricane. There are so far out on the limb with complexity at this point, humans are very unreliable. They are solving a technical problem...not thinking holistically and pondering the complexity storm this shift is entrained in.  Basically there are tons of blinking annunciation and alarms going on all over the place in the control room. 

function, a step was added in alarm response procedure ARP-C3L to trip the operating EDG to protect the 4160V bus and other associated electrical equipment. Second, in 1997, relays were installed to protect respective electrical feeds to the B6 480V electrical bus; preventing potential damage to the LPCI injection valves if the EDG were to fail during a LOOP/LOCA.

On March 6, 2015, Entergy staff performed 4160V electrical bus A5 relay testing in accordance with work

So they never tested the new relays...operators go to bed with nightmares thinking the engineering staff could screw the operating staff in a accident. In the heart of a terrible accident equipment and alarms would't works. A plant have 100,000 of relays and compo-nets, how many of the not working components in very complex accident would it take to confuse the shift?

How many none tested critical to protect the core relays aren't tested for decades?   

order 52425333 and procedure 3.M.3-1, “A5/A6 Buses 4kV Protective Relay Calibration/Functional Test and Annunciator Verification – Critical Maintenance,” Revision 140. In preparation for this testing, Entergy staff noted a change in the drawing which contains the acceptance criteria for the 127-509/1 and 127-509/2 relays. The Entergy staff appropriately updated their relay testing equipment with the proper acceptance criteria; however, did not recognize that the relays had not been tested for the undervoltage dropout setting prior to this date. Testing of the undervoltage dropout setting for relays 127-509/1 & 2 revealed the “as-found” set point to be at 82V compared to the requirement of 106V. Upon inspectors request for information regarding past performance of relays 127-509/1 & 2, Entergy staff discovered that no prior testing for the undervoltage dropout setting had ever been performed. Given that Entergy had not tested these relays over the life of the plant, there was no method to effectively track and trend relay drift from required setpoints which impacted operators’ ability to carry out actions in alarm response procedures. Entergy entered CR-PNP- 2015-1614 and CR-PNP-2015-1623 into the CAP to address the degraded condition. An immediate operability determination was performed and the relays were re-calibrated to their required set points successfully prior to restoration of the X107A EDG. UFSAR Section 8.4.7 for the auxiliary power distribution system establishes a testing frequency for non-technical specification, safety-related 4160V relays in Table 8.4-3 for every four years. These relays are typically tested in accordance with Entergy’s preventive maintenance program and implementation of procedure 3.M.1-1. However, Entergy did not establish testing requirements or a testing frequency to ensure that the undervoltage dropout relay was properly being maintained and functional. Entergy entered CR-2014-1898 into the CAP to address this issue. The immediate operability determination noted that the 480V electrical bus relays installed in 1997 would have performed a similar function to protect the ECCS injection equipment; however, it would not have protected other safety-related equipment in the event of a voltage regulator failure during a LOOP/LOCA. The inspectors confirmed that the 480V electrical bus relays were properly tested and within acceptance criteria as of 2013 to ensure it could have prevented LPCI injection failure.

So you get it, relays critical in a accident to prevent core damage indicating their only remaining power source is failing only gets a insignificant violation. Over all these years with the money spent on inspector and a assortment of inspections, take the starling noneffective CDBI in-depth inspections...why didn't the NRC uncover this first decades ago. What do these inspector do on site???  

(NCV 05000293/2015001-01, Failure to Perform Testing of Safety Related Undervoltage Alarm Relays)

This not a professional staff: Bet you the NRC whispered in their ears fix it. 

The inspectors performed an in-depth review of Entergy’s apparent cause evaluation and corrective actions associated with CR-PNP-2014-1851, “A Negative Trend of Valves\ Trended to Satisfy IST Requirements Has Been Identified.” Specifically, the monitoring of valve stroke times for multiple safety-related valves was not identifying adverse trends in an effective and timely manner, which resulted in equipment operability issues and emergent repairs.

Entergy staff determined there were two apparent causes: 1) component and system engineers and supervisors were generally unaware of their responsibilities to review and trend IST component data as required by Entergy fleet procedures, and 2) the IST engineer did not take timely action to initiate CRs in accordance with program requirements. Entergy staff also determined that system monitoring challenge board meetings were not conducted on a regular basis during this period as required by procedure EN-DC-159, “System Monitoring Program.” 

The inspectors concluded that Entergy staff conducted an appropriate review to identify the likely causes of the IST trending issue. The inspectors also concluded that Entergy staff identified the extent of condition which was mostly the trending of IST program data for the in scope systems; however, the review included an evaluation of the other programs where trending is performed as part of condition monitoring. Corrective actions included a review of the procedure requirements conducted between the system engineers and their supervisors, establishment of a reoccurring schedule for system monitoring challenge board meetings, training for system engineers on monitoring and trending expectations, and revisions of system monitoring plans to include IST data parameter. 

Grave National Crisis, Time To Declare A All Out War: HERION

New Hampshire Union Leader: City streets rife with drug dealers and users

By TIM BUCKLAND

A Manchester police officer displays three packets of freshly confiscated heroin, on left, and two packets of crack. Each packet contains a single dose. (Thomas Roy/Union Leader)

MANCHESTER - The young woman sidled up to the unmarked police car. She knows the men inside are cops, despite their jeans and T-shirts. And they know her.

"I'm not using right now," Kendra Johnson said before asking for $20 and jokingly offering a sexual service.

Officer Matt Jajuga politely told Johnson she has to try to stay off drugs and avoid the type of behavior that recently landed her a stint in Valley Street Jail and notoriety in the news - she was the woman found in January with New Hampshire Motor Speedway General Manager Jerry Gappens engaged in what police called a "sexual act" at the time.

Jajuga, whose brain is a steel trap of names - he knows everyone walking around the area just east of downtown - said the approach he and his partner, Officer Paul Rondeau, take while on plainclothes duty is to talk to people. Each time they stopped during a recent shift where The Sunday News was allowed to ride along, the conversations were light and friendly, whether it was to ask a "known prostitute" to stop sitting on private property or to run a check for warrants on a young man who darted in front of their car.

"You don't want to treat people like they're worthless. That doesn't serve any purpose," Jajuga said.

"It doesn't help to be abrasive. They'll shut down," Rondeau said.

During recent patrol shifts, Rondeau and Jajuga focused on looking for people breaking into cars, a problem in the area on and around Lincoln Street, while Officer Tony Battistelli patrolled a similar area, looking for any laws being broken. 

But the officers' real work is combatting the heroin epidemic, the root cause of most crime in the city. With many state officials focused on trying to increase funding for anti-drug education efforts and to provide more treatment options for heroin addicts, it is police officers who are on the front lines 

***A bigger problemManchester Police Chief David Mara said the problem is more acute now - as opposed to previous so-called drug epidemics involving meth, crack cocaine and even heroin - because of the increase of drug overdoses. The state had more than 300 deaths in 2014 and the city has had more than 30 people die from oversdoses so far this year.

He said he was a patrol officer in the early 1990s when crack cocaine was that era's problem drug.

"I think this is a worse long-term problem," he said of heroin. 

Boston Globe: Heroin exacts an especially savage toll in Plymouth

PLYMOUTH — Fire Chief G. Edward Bradley carries Narcan, the drug that reverses heroin overdoses, nearly everywhere he goes around this sprawling town. Even to the Little League field when he watches T-ball games.It’s part of a personal mission, gnawing and never-ending, that Bradley sees as the greatest challenge of his long career. 

“You see all the alarms around town for the nuclear plant we have here. I wish we had one for heroin,” Bradley said last week. 

Plymouth counted 15 drug-related deaths last year and 313 overdoses, a total 50 percent greater than Taunton’s, a city of similar size that once had been considered the face of the drug epidemic. 

This year, Plymouth is on track to smash its own grim record. By Saturday, the town had recorded 136 overdoses — an average of exactly one a day — and 10 related deaths. 

• Opioid abuse considered widespread, poll finds 

Mass. residents are more worried about drug abuse than are Americans generally, a Boston Globe poll found.

It’s a tally that has risen so quickly, so stunningly, that many Plymouth leaders did not realize the town had an opioid crisis until it overwhelmed them. That includes Police Chief Michael Botieri. 

“It took time for me to become a believer in this epidemic,” Botieri said. Now, nearly everyone believes.“It’s not getting any better, obviously,” Bradley said. “We realized we’re as bad as some of the biggest cities in the state, if not worse.” 

Plymouth’s per-capita overdose rate is significantly higher than hard-hit Worcester’s, a city three times its size that saw a 59 percent rise in overdoses last year.While the numbers grow, so has Plymouth’s response... 

Opioid abuse considered widespread, poll finds

Nearly three-quarters of Massachusetts adults believe heroin use is an extreme or very serious problem in the state, and almost four in 10 adults know someone who has abused prescription painkillers in the last five years, according to a survey by The Boston Globe and the Harvard T.H. Chan School of Public Health. 

The poll also found that Massachusetts residents are more worried about opioid abuse than are Americans generally, and that more adults here believe prescription drug abuse is getting worse...

Brunswick's DG Flex Building Already has Roof Leaks?

Oh, brother,

WO 13354886, March 30, 2015, FLEX diesel building roof leaks

So basically a backup, backup system much likes the flex program that the utilities don’t spend the resources to keep these machines fully operable. It is so predictable and foreseeable...

Limerick Generating Station 2015-001 

“fire safe shutdown diesel (FSSD) generator 

Introduction. The inspectors identified a Green NCV of LGS Units 1 and 2 operating license condition 2.C(3), Fire Protection, because Exelon did not implement and maintain in effect all provisions of the NRC approved fire protection program. Specifically, Exelon did not implement and maintain a maintenance program to ensure the operability of the FSSD generator by not ensuring a fuel oil supply was specified or was protected for typical winter cold temperatures.
 The FSSD generator is provided to power portable ventilation fans used for smoke removal and indoor temperature control in the control room, remote shutdown panel room, and auxiliary equipment room following fires which could impact normal ventilation systems. The portable ventilation fans and FSSD generator enable LGS to reach and maintain fire safe cold shutdown conditions assuming ventilation failures due to fire damage. However, the unavailability of the FSSD generator would not by itself prevent LGS from reaching and maintaining safe shutdown. 

Entergy's CEO Denault Sizing Up Environment

 Entergy (ETR) Stock Rises After CEO Denault Appears on Jim Cramer's 'Mad Money'

NEW YORK (TheStreet) -- Shares of Entergy (ETR - Get Report) rose 0.65% to $74.24 in morning trading Thursday after chairman and CEO Leo Denault appeared on Jim Cramer's Mad Money show on CNBC.

Denault said the industrial renaissance in America's south and along the Mississippi River is ongoing. Furthermore, industries are taking advantage of Entergy's

Does Denault think their nuclear fleet should be producing electricity 20% lower than the nuclear fleet average across the USA? Is that the root of their problem. These guys are the Walmart of the Utility industry. Do you want Walmart running a nuclear power plant? 

electricity rates, which are 20% below the national average, in order to build new plants. This gives Entergy numerous growth opportunities to increase its dividend, he added.

Entergy has a 4.5% yield.

Denault also talked about the recent transformer fire outside the company's Indian Point nuclear plant in Westchester County, New York. He noted the fire was extinguished quickly and the plant was safely shut down, but it must stay offline for a few weeks because the transformers are what transmit the power from the plant to the grid.

Cramer asked about new plants under construction, and the CEO explained that the company is working quickly to replace outdated plants and increase its capacity in order to meet demand. Many of the new plants are natural gas, which are the quickest to construct, but the company is also building nuclear and solar plants.

Cramer again recommended Entergy on the show.

Separately, TheStreet Ratings team rates ENTERGY CORP as a Buy with a ratings score of A-. TheStreet Ratings Team has this to say about their recommendation:

"We rate ENTERGY CORP (ETR) a BUY. This is based on the convergence of positive investment measures, which should help this stock outperform the majority of stocks that we rate. Among the primary strengths of the company is its attractive valuation levels, considering its current price compared to earnings, book value and other measures. We feel its strengths outweigh the fact that the company has had sub par growth in net income."

Highlights from the analysis by TheStreet Ratings Team goes as follows:

§  ENTERGY CORP's earnings per share declined by 26.3% in the most recent quarter compared to the same quarter a year ago. This company has reported somewhat volatile earnings recently. But, we feel it is poised for EPS growth in the coming year. During the past fiscal year, ENTERGY CORP increased its bottom line by earning $5.22 versus $3.98 in the prior year. This year, the market expects an improvement in earnings ($5.50 versus $5.22).

§  ETR, with its decline in revenue, underperformed when compared the industry average of 2.8%. Since the same quarter one year prior, revenues slightly dropped by 9.0%. Weakness in the company's revenue seems to have hurt the bottom line, decreasing earnings per share.

§  In its most recent trading session, ETR has closed at a price level that was not very different from its closing price of one year earlier. This is probably due to its weak earnings growth as well as other mixed factors. The stock's price rise over the last year has driven it to a level which is somewhat expensive compared to the rest of its industry. We feel, however, that other strengths this company displays justify these higher price levels.

§  Net operating cash flow has decreased to $610.96 million or 20.36% when compared to the same quarter last year. Despite a decrease in cash flow of 20.36%, ENTERGY CORP is in line with the industry average cash flow growth rate of -25.99%.

The Blaa, Blaa Blaa NRC Chairman

You notice all the print space devoted to bureaucratic issues and Fukushime...they never talk about plant problems. This sounds like the language of a captured regulator.

What is the NRC chairman's perspective on the top five problems at the plant level...this guy got a lot of experience.  

Remarks by NRC Chairman Stephen G. Burns to the 2015 Nuclear Energy Assembly May 13,2015 – Washington, D.C.
 Good afternoon. I appreciate the opportunity to appear before you today at NEI’s annual Nuclear Energy Assembly. I plan to touch on a few topics that I hope will be of interest to the audience here today. I have now served for about four and a half months as Chairman of the NRC, having been designated by President Obama as Chairman on January 1 of this year. As you may know, I had earlier retired from the NRC in 2012 after a nearly 34-year career that culminated in my service as the agency’s General Counsel. To describe the experience as a bit surreal doesn’t do it justice. As a young attorney entering the NRC in 1978, I could never have imagined that someday I would be Chairman of this great organization. Now, returning to the NRC after my three-year hiatus in Paris at the OECD Nuclear Energy Agency, I have the unique opportunity to experience the agency yet again from an entirely new vantage point...

Arkansas Nuclear One (Entergy) rated worst nuke plant in U.S

Arkansas Nuclear One rated worst nuke plant in U.S.

RUSSELLVILLE, Ark. (KTHV) - Arkansas Nuclear One in Russellville ranks among the worst nuclear plants in the country for federal performance ratings. The low rating comes as a result of two major issues that have led to what the U.S. Nuclear Regulatory Commission calls "a significant decline in plant performance." "We're taking this very seriously, I do view this as an opportunity. It's an unfortunate place to be but it also yields a lot of good opportunity for us," said Arkansas Nuclear One Site V.P. Jeremy Browning. "You don't just want to fix the symptom, you want to fix the underlying cause that drove that symptom so it doesn't ever happen again." 

Browning said he's not happy about his plant being the only one in the country being scrutinized this heavily by the federal Nuclear Regulatory Commission, but he was quick to point out that the plant is fully committed to getting back on track. Nuclear One's decline in performance is related to a 2013 accident that killed 24-year-old Wade Walters and injured eight others. Then, in January of this year, regulators found problems with the plant's flood protection systems. "What I'm talking about is: why did we not detect those issues before they became self-revealing" added Browning. "That's what we need to do. We are not going to have another failed project like we did in 2013, we're not going to have a problem with our flood barriers, we have fixed that – but something allowed those to self-reveal themselves to us and we can't tolerate that." Part of the fix will include a safety culture assessment according to NRC spokesperson Lara Uselding. "Safety culture is just good decision-making by the workers, good problem identification and understanding that when you have a problem how to prioritize it and then how to fix it," said Uselding. "The NRC does believe that the plant can operate safely and therefore they have not been asked to shut down, they have demonstrated sustained improvement so far with making corrective action to some of these issues that we've discussed." Browning says he's confident Nuclear One will be able to address the issues and continue production without any further issues. 

Sequotah: Many Fuel Pin Leaks Spewing Radiation All Over The Plant

This got to be going again all over the place? It is a repeated industry crisis. 

SUBJECT: SEQUOYAH NUCLEAR PLANT - AMENDED NRC INTEGRATED INSPECTION REPORT05000327/2014003 AND 05000328/2014003

Source Term Reduction and Control: The inspectors reviewed the collective exposure three-year rolling average (TYRA) from 2011 - 2013 and reviewed historical outage collective exposure trends. Through interviews with licensee staff and document review, the inspectors assessed the licensee’s current activities related to source term reduction, including elevated zinc injection on U2, on-line chemistry using pH 7.4 to minimize corrosion product transport, extended reactor coolant pump run time to allow better cleanup during shutdown, ultrasonic fuel cleaning, and response to fuel defects during previous operating cycles. The inspectors discussed the unexpectedly high activity o shutdown crud burst and changes expected in the short and long term relative abundances of Cobalt-58 and Cobalt-60 that would result from the change in the steam generator tube alloys and increasing the number of steam generator tubes by about a third. The dose implications of the various cobalt reduction activities coupled to the
change in tube alloys for the next few outages was also discussed

Plant Maintenance Big Picture By The Professional Reactor Operator Society

NORTH ANNA POWER STATION – NRCINTEGRATED INSPECTION REPORT

By Bob Meyer

Maintenance, maintenance safety culture, maintenance procedures, maintenance wrench time are a weak link in most nuclear plants. Years ago INPO by the direction of their board of directors reduced maintenance training and knowledge of the nuclear plant to a weaken state it is today. Take a look at the NRC violation, the rework and errors that are made. The landscape has changed since INPOs inception, and the lack of focus on all departments has caused significant degradations to the integrated wellbeing of the organization. There has been multiple paradigm shifts in work control and yet no new training or qualifications have changed. Work control provides directions and guidance on safety related equipment, with no training analysis on their performance… they have no training. Everyone that puts their hands on the equipment need detailed training, everone that writes procedures, work instructions for safety related training need detailed training. They all need to be part of the Systematic Approach to Training (SAT) process.

Here is the report...

The Ghost Monticello's HPCI

This is how risk perspectives looks like while on drugs.

In a big accident, the operating staff at the beginning has very limited resources. They would have no capability to assess if the steam lines were clear. They would assume HPCI was broken and to use it would create new dangers with the condensate damaging other components. So the operators would walk right past the damaged equipment.

This is another huge flaw in risk perspectives. It doesn't matter what the condition is of the component is...it only matter what the operators perception is of safety equipment. These are the lessons of TMI and Davis Besse.

I would consider this equipment broken until proven safe...not available to the accident. Calling it this way would jack up the worth of a broken HPCI...incentive not to let it happen again.  

HIGH PRESSURE COOLANT INJECTION INOPERABLE DUE TO CONDENSATION IN STEAM LINE 

"At 0537 CDT on March 21, 2015, following the High Pressure Coolant Injection (HPCI) system quarterly pump and valve surveillance, after HPCI was removed from service, an alarm for the HPCI Turbine Inlet High Drain Pot Level did not reset. This indicated that LS-23-90 (HPCI Steam Supply Drain High Level Bypass) did not reset, which could be an indication that condensate exists in the steam line. The system responded as designed but the alarm did not clear as expected. Without assurance that the condensate has been removed from the HPCI steam line, HPCI remains inoperable for reasons other than the planned surveillance. As a result, this condition is being reported under 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented fulfillment of the safety function at the time of discovery.

"The health and safety of the public was maintained as the plant was in a normal condition with no initiating event in progress.

"The NRC Resident Inspector has been notified."
The State of Minnesota will be notified.

* * * RETRACTION FROM RANDY SAND TO DANIEL MILLS AT 1445 EDT ON 5/11/15 * * *
"On March 21, 2015, Northern States Power Minnesota reported a condition that could have prevented the fulfillment of a safety function under 10 CFR 50.72(b)(3)(v)(D). The High Pressure Coolant Injection (HPCI) System was declared inoperable for a reason other than planned maintenance due to the failure of the HPCI Steam Supply Drain Hi Level Bypass Level Switch to clear the high level alarm subsequent to actuation. 

"An engineering evaluation was performed and concluded that the function of the primary pathway to remove condensate remained unchallenged by the condition present

Do they got this thermography gear available to the operators...so they can immediately see if the condensate is clear??? Is thermography qualified to check the conditions of safety equipment. 

on the level switch This conclusion was also validated via thermography with the HPCI steam supply pressurized and bypass valve open. The verification that the primary pathway was functional provides reasonable assurance that the HPCI steam supply was always clear of condensate supporting the ability of HPCI to perform its required safety function. Therefore, the condition present on the level switch did not render HPCI inoperable. The conclusions of the engineering evaluation provide the basis for retraction of the ENS report made on March 21.
"The NRC Resident Inspector has been notified."
The licensee will also notify the State of Minnesota.

Number 2 event report:

HIGH PRESSURE COOLANT INJECTION INOPERABLE DUE TO CONDENSATION IN STEAM LINE

"At 0537 CDT on March 21, 2015, following the High Pressure Coolant Injection (HPCI) system quarterly pump and valve surveillance, after HPCI was removed from service, an alarm for the HPCI Turbine Inlet High Drain Pot Level did not reset. This indicated that LS-23-90 (HPCI Steam Supply Drain High Level Bypass) did not reset, which could be an indication that condensate exists in the steam line. The system responded as designed but the alarm did not clear as expected. Without assurance that the condensate has been removed from the HPCI steam line, HPCI remains inoperable for reasons other than the planned surveillance. As a result, this condition is being reported under 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented fulfillment of the safety function at the time of discovery.

"The health and safety of the public was maintained as the plant was in a normal condition with no initiating event in progress.

"The NRC Resident Inspector has been notified."

The State of Minnesota will be notified.

* * * RETRACTION FROM RANDY SAND TO DANIEL MILLS AT 1445 EDT ON 5/11/15 * * *

"On March 21, 2015, Northern States Power Minnesota reported a condition that could have prevented the fulfillment of a safety function under 10 CFR 50.72(b)(3)(v)(D). The High Pressure Coolant Injection (HPCI) System was declared inoperable for a reason other than planned maintenance due to the failure of the HPCI Steam Supply Drain Hi Level Bypass Level Switch to clear the high level alarm subsequent to actuation.

"An engineering evaluation was performed and concluded that the function of the primary pathway to remove condensate remained unchallenged by the condition present on the level switch This conclusion was also validated via thermography with the HPCI steam supply pressurized and bypass valve open. The verification that the primary pathway was functional provides reasonable assurance that the HPCI steam supply was always clear of condensate supporting the ability of HPCI to perform its required safety function. Therefore, the condition present on the level switch did not render HPCI inoperable. The conclusions of the engineering evaluation provide the basis for retraction of the ENS report made on March 21.

"The NRC Resident Inspector has been notified."

The licensee will also notify the State of Minnesota.

Notified R3DO (Peterson).

Oyster Creek: Unreviewed Safety Problem

Seem they had another trip over a transformer short. Is this the end of Oyster Creek? Will plant operation become more chaotic as 2019 approaches? 

Licensing never considered the closing or heading to permanent shutdown problems with nuclear power plants. Do we need new rules???

It is when the parent company starts throttling down money to the plant, because after all, we are going to be shutting down in a few years. It not prudent wasting money on a dying plant. 

In the closing period of the life of the plant, the NRC doesn't fully enforce the license or rules of agency because we feel so sorry for these employees..all we got to do is get through another year or two, then the site will finally be silent.

We are massively dropping our shields in the closing period of plant operation. It would be a terrible shame if in the last year of a plant's life, an event or accident shames the whole industry.

And spinning in the background is Exelon whining (begging) to save financially a host of wounded Illinois nuclear plants.

(I not sure if shutting down a host of nuclear plant is a way to booster grid electricity prices or stabilize the decline of electricity prices because of fracting? 

Traitor Matt Wald: NYT's Nuclear Industry Expert

One wonders now if we ever got a objective, complete and honest nuclear plant story out of him while he was a reporter for the New York Times. 

We certainly live in such corrupt times...

"The following is a guest post from Matt Wald, senior director of policy analysis and strategic planning at NEI. Matt joined us in April after 38 years at The New York Times." 

Clinton 50.59

works in progress....when do you think they made the switch gear fully seismically  qualified...was it a recent fix...

What is going on here? The NRC recently tazed Millstone in a 2002 10 CFR 50.59 violation and now Clinton is being zapped by a non sited  1979 50.59 violation. What is the message the NRC is trying to say?

The national problem with screenings, 50.59 and LAR...you never know what the sample size is compared to all  screenings, 50.59 and LARs. The complaint with the San Onofre SG 50.59 is the agency is resourced restrained and the agency is a sample agency. The only get to sample a small amount of the documents and report. Basically a plant with  more than 800 employees can bury the two or more inspectors on site with paperwork.

Basically a 50.59 is a analysis if a issue needs permission to change the licencing conditions of a plant.

I still don't understand what caused Clinton in 1997 to discover their Div 1,2 and 3  breaker weren't fully seismically qualified in the racked out position. It is interesting, why not always remove the racked out breaker from the compartment? An empty breaker bus  cabinet has to seismically safety.  Then it will be seismically qualified

On February 27, 1997, the licensee generated Condition Report (CR) 1-97-02-273, “ABB [ASEA Brown Boveri] and General Electric Breakers Not Seismically Qualified in Racked Out Position.”

So once they discovered the breakers weren't fully seismically qualified, they were  required to enter Tech Specs and enter a LCO. At some near point, if not fixed they were facing a shutdown. Millions of bucks a day were on the line by shutting down unnecessarily.

So the solution was to write up a silly evaluation saying if the racked out breaker was a short time duration, the risk were so slight as to not required NRC permission. What this really is doing by getting NRC permission according to the lessens learn from San Onofre, is to informing the public and bring them along on licencing changes. But this is circa 1997. It also required Clinton to write a public evaluation about the possible change.

The inspectors reviewed NEI 96-07, Section 4.3.2, “Does the Activity Result in More Than a Minimal Increase in the Likelihood of Occurrence of a Malfunction of an structure, system, or component (SSC) Important to Safety?,” which stated that changes in design requirements for earthquakes, tornadoes, and other natural phenomena should be treated as potentially affecting the likelihood of malfunction.

It does increase risk if the Inop is a short duration? This risk perspective goes to their heads if they are not careful. Again it is certainty/uncertainty gaming...selectively releasing information to what is favorable.

On March 20, 1997, the licensee completed “Risk Evaluation for Seismically Indeterminate Switchgear Configurations,” which was included as an attachment to the licensee’s letter Y-106400 to address the switchgear’s seismically unanalyzed conditions. The purpose of the evaluation was to address the risk significance of the seismically unanalyzed conditions. The evaluation concluded there were no adverse impacts on the intended safety function of the affected switchgear, and other adjacent cubicles’ in-service devices (i.e., relays, instruments, etc.); provided the duration of the seismically unanalyzed conditions only existed for a limited period of time.

This is when it was entered into the USAR.  So it was inop from Feb 27 to the illegal, unethical and inappropriate April 22 entry into the USAR. So why didn't the NRC enforce tech specs and a shutdown? You want to make these guys pay a horrendous price for not purchasing and acquiring appropriate grade and tested safety equipment. You want to give them a incentive to fix tier shaky bureaucracy. See, this is what I am talking about with incentivizing a big corporation to do the right thing. Was the 1982 $92 million dollar fine to the Clinton nuclear plant the largest fine by the agency? This was three years after TMI???

So in the below, we see the terrible flaw in the NRC oversight of nuclear plants. We get to see the hyper technical violations and how they proportion violations through risk perspectives in the NRC inspection reports that nobody understands. We never get to see the real story behind the ultra technical story...the real mover with why the problem develops. Illinois Power was right in their 199 evaluation and the 2015 NRC 50.59 inspection report was completely off base according to the perspectives on  the condition of the plant in 1997. A grievous wrong has been done to Illinois power and the Clinton nuclear plant by this 50.59 violations.

So maybe a 1997 historic perspective is in order with the Clinton plant.

Most of the nukes is Illinois including all of Comed/ Exelon nuke plants were in big trouble with the NRC towards the end of the 1990s.  Illinois Power tried to build a single plant nuclear plant...they made a mess out of it. By 1997, the plant had been shutdown for a year, two more years of shutdown was ahead of them. At the 1997 inspection violation point, the future of the Clinton nuclear plant was very bleak.  Maine Yankee was permanently shutdown in 1997 and the two plant Zion plant owned by Commonwealth Ed was heading towards a permanent shutdown in 1998. Region III had to be a absolute basket case in 1997. In 1997 the QA and safety bureaucracy in the Clinton plant was in total disarray and utter breakdown? 

• In 1982 the Nuclear Regulatory Commission issued ten separate stop-work orders at the Clinton site resulting from concerns that inspection and documentation of completed work was not keeping pace with construction. That same year IP agreed to pay a $90 million NRC fine, stemming from charges that NRC quality control inspectors had been intimidated at the construction site and the company failed to appropriately document and implement electrical quality assurance programs.

• In 1997, it was also said to be producing "some of the highest electric rates in the midwest". After less than a decade of operation the plant's original owner, Illinois Power, had to close it in 1996 following some technical problems and safety violations resulting in a $450,000 fine.( Shutdown from 1996 to 1999) 

• Having deduced that it was not economical to own and operate only one nuclear generating station in the newly deregulated market, they kept it shut down during around 3 years whilst looking for an interested buyer.^[6] Exelon Corporation bought it for a more modest price of $40 million, with the purchase including the fuel in the reactor vessel and responsibility of all the radioactive waste in the spent fuel storage pool. The Operator and Owner is the Exelon Corporation. 

• On April 22, 1997, the licensee applied the results of the evaluation and updated the safety analysis report per USAR Change 7-209, “Section 3.10, Qualification of Seismic Category I Instrumentation and Electrical Equipment.”

In 1982 the Nuclear Regulatory Commission issued ten separate stop-work orders at the Clinton site resulting from concerns that inspection and documentation of completed work was not keeping pace with construction. That same year IP agreed to pay a $90 million NRC fine, stemming from charges that NRC quality control inspectors had been intimidated at the construction site and the company failed to appropriately document and implement electrical quality assurance programs. 

 
This issue was a
  

On February 27, 1997, the licensee generated Condition Report (CR) 1-97-02-273, “ABB [ASEA Brown Boveri] and General Electric Breakers Not Seismically Qualified in Racked Out Position.”

What is going on here? The NRC zapped Millstone of a 2002 10 CFR 50.59 violation. And now Clinton is being zapped by a non sited  1979 50.59 violation.

Basically in 1997 Clinton discovered  having a switchgear in a racked out position, they had  no proof this position was seismically qualified. At this point, they were supposed to enter tech specs, I am not sure of the TS requirement and when they needed to be shutdown.

Instead Clinton changed the UFSAR without NRC permission saying if it was less than 24 hours.

On February 27, 1997, the licensee generated Condition Report (CR) 1-97-02-273, “ABB [ASEA Brown Boveri] and General Electric Breakers Not Seismically Qualified in Racked Out Position.”

The evaluation concluded there were no adverse impacts on the intended safety function of the affected switchgear, and other adjacent cubicles’ in-service devices (i.e., relays, instruments, etc.); provided the duration of the seismically unanalyzed conditions only existed for a limited period of time. On April 22, 1997, the licensee applied the results of the evaluation and updated the safety analysis report per USAR Change 7-209, “Section 3.10, Qualification of Seismic Category I Instrumentation and Electrical Equipment.”

The evaluation concluded there were no adverse impacts on the intended safety function of the affected switchgear, and other adjacent cubicles’ in-service devices (i.e., relays, instruments, etc.); provided the duration of the seismically unanalyzed conditions only existed for a limited period of time.

On April 22, 1997, the licensee applied the results of the evaluation and updated the
safety analysis report per USAR Change 7-209, “Section 3.10, Qualification of Seismic
Category I Instrumentation and Electrical Equipment.”

April 23, 2015: CLINTON POWER STATION, EVALUATIONS OF CHANGES, TESTS, AND EXPERIMENTS AND PERMANENT PLANT MODIFICATIONS BASELINE

INSPECTION REPORT05000461/2015008

Severity Level IV-Green. The inspectors identified a finding of very-low safety significance, and an associated Non-Cited Violation of Title 10, Code of Federal Regulations Part 50, Section 59, “Changes, Tests and Experiments,” (effective January 1, 1997) for a procedure change dated May 2, 1997, where the licensee allowed safety-related switchgear to operate for a limited period of time during plant operation in equipment configurations that were seismically unanalyzed. Specifically, for Safety Evaluation Log 97-060, “CPS [Clinton Power Station] Procedure No. 1014.11,” Revision 0, the licensee failed to include a written safety evaluation which provided the bases that concluded for all switchgear configurations that a seismically unanalyzed condition does not involve an unreviewed safety question, and the possibility for a malfunction of a different type than any evaluated previously in the Safety Analysis Report may be created. The licensee entered the issue into their Corrective Action Program as Action Request 02471583, “NRC Mod 50.59 Inspection Safety Eval 97-060 for CPS 1014.11,” dated March 20, 2015.

On May 2, 1997, the licensee issued Procedure CPS 1014.11, “6900/4160/480V Switchgear/Circuit Breaker Operability Program,” which allowed switchgear in a seismically unanalyzed condition to be considered operable for up to 48 hours as long as administrative controls were implemented. After the 48 hours, the switchgear was then declared inoperable. The licensee’s associated Safety Evaluation Log 97-060, “CPS Procedure No.  1014.11

See, this is what I am talking about with incentivizing a big corporation to do the right thing. Was the 1982 $92 million dollar fine to the Clinton nuclear plant the largest fine by the agency? This was three years after TMI???