Rash of Problems Testing Instrumentation at Nuclear Plants

Having troubles at nuclear plants hiring I&C guys?

Event Number: 52643
Facility: PILGRIM Region: 1 State: MA Unit: [1] [ ] [ ] RX Type: [1] GE-3 NRC Notified By: KEVIN OROURKE HQ OPS Officer: BETHANY CECERE	Notification Date: 03/27/2017 Notification Time: 21:54 [ET] Event Date: 03/27/2017 Event Time: 18:25 [EDT] Last Update Date: 03/27/2017
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(D) - ACCIDENT MITIGATION	Person (Organization): BILL COOK (R1DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	Y	100	Power Operation	100	Power Operation

Event Text

HPCI DECLARED INOPERABLE DUE TO INADVERTENT ISOLATION "On March 27, 2017, at 1825 hours EDT, with the reactor at 100 percent core thermal power and steady state conditions, technicians inadvertently caused a High Pressure Coolant Injection (HPCI) System isolation, by testing the incorrect temperature switches in the TIP [Traversing In-core Probe] room. Pilgrim Nuclear Power Station (PNPS) was performing testing on the temperature switches for Reactor Core Isolation Cooling (RCIC), but the HPCI temperature switches were inadvertently actuated causing HPCI to isolate. "The Limiting Condition for Operation (LCO) Action Statement 3.5.c.2 has been entered and the planned testing has been secured pending further investigation. PNPS is providing an 8-hour non-emergency notification that the HPCI System was declared inoperable in accordance with 10 CFR 50.72(b)(3)(v)(D), an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. HPCI was returned to Operable within 40 minutes." The licensee notified the NRC Resident Inspector and the Commonwealth of Massachusetts.

Page Last Reviewed/Updated Tuesday, March 28, 2017

Junk Plant Hope Creek: Their Employees Turning Agaisnt Them

05000354

Does this happen often? Why would a employee lie?

HOPE CREEK GENERATING STATION - NRC INVESTIGATION REPORT NO. 1-2016-003
Dear

Dear Mr. Sena:

This letter refers to an investigation initiated on November 5, 2015, by the NRC Office of Investigations (OI) and conducted at the PSEG Nuclear, LLC (PSEG) Hope Creek Generating Station (Hope Creek). The investigation was conducted to determine whether an instrument and control (I&C) technician had deliberately failed to follow site procedures resulting in a reactor scram. Based on the evidence gathered during the investigation, the NRC preliminarily determined that a (now-former) PSEG employee at Hope Creek deliberately failed to follow a procedure...

Factual Summary of NRC Office of Investigations (OI) Case No. 1-2016-003

On September 28, 2015, an instrument and control (I&C) technician completed procedure HC.IC-FT.SA-0001, “Redundant Reactivity Control System (RRCS) – Division I Channel A” and successfully tested the ‘A’ channel of the RRCS. The I&C technician then proceeded into procedure HC.IC-FT.SA-0003, “RRCS – Division I Channel B” to test the ‘B’ channel of the RRCS. While the technician was performing this procedure, the reactor tripped. To determine the cause of the reactor trip, on September 30, 2015, PSEG performed complex troubleshooting, which included reviewing the data saved from plant parameters. Based on the troubleshooting, PSEG determined that the I&C technician had made an error during the surveillance testing, causing both RRCS channels to trip and the reactor to scram.

OI interviewed a PSEG staff engineer involved in the troubleshooting. The engineer testified that he analyzed real-time printouts of reactor parameters at the time of the event to recreate the scenario on the reactor simulator. The engineer stated that, from the simulation, it was determined that the I&C technician had incorrectly selected the ‘A’ channel of RRCS and then selected the ‘B’ channel with the test input still inserted in the ‘A’ channel. This error then caused the reactor recirculation pumps to trip leading to the reactor scram. Additionally, the engineer testified that the full RRCS system was reviewed as part of the troubleshooting and no other failures were identified.

The I&C technician testified that he had received training and was fully qualified to perform surveillances of the RRCS and had performed this particular surveillance   

The employee says something else broke.

numerous times. The technician acknowledged that he had received training on procedure use and adherence and understood that if an issue occurred, to stop and resolve the issue before moving forward in the procedure. The I&C technician stated that on September 28, 2015, he and another technician had been assigned to perform the RRCS surveillance on the Division 1 ‘A’ and ‘B’ channels. The technician testified that the cause of the reactor scram was “something went wrong with RRCS,” adding that he did not make any mistakes or deviate from the procedure. The I&C technician could not provide an explanation for the contradiction between PSEG’s determination for the cause of the scram (i.e. human performance error) and the technician’s own testimony.

OI reviewed the copy of HC.IC-FT.SA-0003, used by the I&C technician on September 28, 2015. The technician had initialed the warning at the start of the applicable section of the procedure which stated “Extreme caution should be exercised with key functions on Display Monitor. Careless keyboard manipulation can cause a reactor scram. If any doubt or questions arise, THEN CONTACT Job Supervision immediately.” Contrary to this warning, the I&C technician, as proven through plant data, did not stop and contact supervision after incorrectly selecting the ‘A’ channel of RRCS. Instead, he selected the ‘B’ channel with the test inputs still inserted in the ‘A’ channel.
OI concluded based on the preponderance of evidence, that the I&C technician deliberately failed to follow this procedure.

Hope Creek Generating Station Technical Specification 6.8.1.d, “Procedures and Programs,” requires that written procedures shall be established, implemented, and maintained for surveillance and test activities of safety-related equipment. HC.IC-FT.SA-0003, “Redundant Reactivity Control System – Division 1 Channel B, C-22-N-403E, N402E ATWS Recirculation Pump Trip,” cautions that “Careless keyboard manipulation can cause a reactor scram. IF any doubt or questions arise, THEN contact Job Supervisor immediately.”

ENCLOSURE 2
APPARENT VIOLATION

Contrary to the above, on September 28, 2015, PSEG did not properly implement a procedure for a surveillance activity of safety-related equipment when the individual performing an RRCS surveillance test made an error and rather than immediately stopping and informing the job supervisor, attempted to correct the error. Specifically, when manipulating the keyboard, the individual selected the wrong channel to test. Rather than contacting the job supervisor, the individual attempted to correct for the error by selecting the proper channel with test inputs still inserted in the other channel, which ultimately led to a dual recirculation pump trip, alternate rod insertion (ARI) initiation, and a reactor scram.

About a year later, the exact same kind of event, but different instrumentation occurred at shutdown.   

Licensee Event Report 2016-005-01

DESCRIPTION OF OCCURRENCE

On November 5, 2016 at 0404 a RRCS I ARI {JC} signal was generated while excess flow check valve testing was in progress. The RRCS/ARI signal was generated due to trip signals on reactor pressure vessel dome pressure high channel "B" (expected for testing) and RPV water level low channel "A" (unexpected for testing condition). The unexpected signal was generated during the performance of isolating transmitters during preps for excess flow check valve (EFCV) testing. This signal would have been reset in accordance with procedures if followed. There were two procedures being executed in parallel by technicians to perform the excess flow check valve testing. The test procedure is written to test all EFCV's, with the EFCV's being separated into 21 groups based on channel and instrument rack relationships. Only one of the EFCV groups, group J, was to be tested. A second procedure is used to align and isolate the instrument racks for testing. Since only one group was to be tested, the evolution required partial procedure performance and coordination of both procedures to accomplish the test. In marking up the procedures for partial performance, the steps to isolate transmitters that were not to be tested were marked Not Applicable (N/A). In the process of marking up the procedure, the steps to reset any RRCS trips was also inappropriately marked N/A. As a result, the trip of the "A" channel low RPV water level was not reset prior to performing the test of the "B" channel high RPV pressure.

The cause the event was inadequate procedural guidance which resulted in a personnel error associated with partial procedure use.

Junk Plant Pilgrim: Why not Employee Sabotage within this LER?

Update march 24

Lawmakers in Pilgrim zone urge NRC to shut nuke plant down
March 22, 2017

eclark@wickedlocal.com

PLYMOUTH – Some supervisors on performance improvement plans didn't know they were on performance improvement plans.

Wrong names appeared on some of these plans.

A part broke on a generator and a part that didn't match that part was used to replace it. An event report for an issue with the plant wasn't filed within the required 60 days.

A problem pertaining to the dry well was "closed out" without being fixed.

There was failures to take corrective action and to "adequately implement" a fix to the safety culture problem.

A temporary fix of injecting sealant to stop a water leak in the residual heat exchanger was treated as a permanent solution, not a temporary one.

The wrong part of a safety relief valve was fixed, and the root cause of the problem went unnoticed…

Reposted from 1/23/2017

I am getting from some plant employees there has been a agreement amongst them to minimally participate with the NRC. There are so pissed off with the bullshit spinning games of NRC and

"The failure is attributed to minimal engagement of the pressure adjusting threaded union for the relief valve setting of 15 psig, and there is some contribution from either engine vibration or possibly human error which makes the cause indeterminate."   

Entergy this is their way protesting it and getting attention. They are sick and tired of working in a poorly funded plant. They are sick and tired of constantly of being under the intimidation of being fired by everyone. They are sick and tired with Entergy threatening they will get fired for telling the truth to the NRC and NRC telling them they will get them fired for not telling the truth to the agency.

December 9, 2016

SUBJECT: Licensee Event Report 2016-008-00, Emergency Diesel Generator 'A' Past lnoperability

On September 28, 2016, while performing the pre-start checks prior to running the Emergency Diesel Generator (EDG)-A •or the monthly Technical Specification (TS) surveillance, the oil level in the EDG radiator fan right angle gearbox was found ~o be low and additional checks found the gearbox oil pressure relief valve in a loose state which provided a pathway for gear oil to be pumped out of the gear box while the EDG was operating. EDG-A was declared inoperable, the relief valve was repaired, pressure tested and the pressure adjusting threaded union was staked to eliminate any risk from vibration induced motion in the future, the gearbox oil was replaced and the EDG run for a post-maintenance test.

A Functional Failure Determination completed on October 11, 2016 determined that the EOG would not have been able to run for its stated mission time of 30 days. This condition existed for a period of 28 days since the last surveillance test on August 31, 2016 which is greater than the TS Allowed Out of Service Time (AOT) of 72 hours. However, the Station Black Out Diesel Generator was available during this time frame. This issue is reportable under 10 CFR 50. 73(a)(2)(i)(B) as an Operation or Condition which was Prohibited by the plant's TSs. On September 15, 2016 EDG-B was made inoperable to perform its monthly operability run. This created a situation where •or a brief period of time both EDGs were inoperable which is a condition that could have prevented the fulfillment of the safety function of a system needed to shut down the reactor and maintain it in a safe condition, remove residual heat, and mitigate the consequences of an accident which is reportable in accordance with 50. 73(a)(2)(v)(A), 50. 73(a)(2)(v)(B), and 50.73(a)(2)(v)(D). EDG-B remained available and could quickly have been restored by manual action to an operable condition if needed during the operability run.

The safety objective of the emergency diesel generators (EDGs) is to provide a source of on-site AC power adequate for the safe shutdown of the reactor following abnormal operational transients and postulated accidents assuming a complete loss of off-site power, as described in Pilgrim Nuclear Power Station (PNPS) Updated Final Safety Analysis Report (UFSAR). Two EDGs and their associated fuel supply systems provide a single failure proof source of standby AC power. Pilgrim EDGs are 2600 KW ALCO 251-F type diesel generators. These EDGs are designed to automatically start upon receiving a valid signal, and come to operating speed ready to assume load. Each generator is sufficient to power all loads on its emergency bus upon failure of all off-site power. Each generator has the ability to pick up loads in sequence within a specified time period. The two EDGs at PNPS are cooled by a self-contained system consisting of radiators and a fan that is driven through a right angle gearbox.

The standby AC power source provides two independent diesel generators as the onsite sources of AC power to ~he emergency service portions of the station Auxiliary Power Distribution System. Each onsite source provides ~C power to safely shut down the reactor, maintain the safe shut down condition, and operate all auxiliaries necessary for station safety.

Historical review revealed that this fan drive gearbox was replaced on the EOG-A in the May 2000 time frame. At ~hat time, the original gearbox, Cotta Transmission Model Number J1327-2 was replaced with an upgraded Model Number J1327-3. Correspondence with the OEM vendor indicated the inside of the cases were identical with the only major physical change on the outside which was the addition of a relief valve in the oil circuit. Changes to the gearbox inspections were not updated to include any inspections or preventive maintenance for the relief valve.

EVENT DESCRIPTION

On September 28, 2016, while performing the pre-start checks prior to running the Emergency Diesel Generator (EDG)-A monthly Technical Specification (TS) surveillance, the oil level in the EOG radiator fan right angle gearbox was found low and additional checks found the gearbox oil pressure relief valve was loose.

The two EDGs at PNPS are each cooled by self-contained systems consisting of radiators and fans that rotate through a right angle gearbox. At the time of discovery, even though the oil level was low, the EOG would have started on a valid start signal. However, it would have been losing gearbox oil and we conservatively assumed it would have overheated due to failure of the cooling fan from gearbox damage. ~Functional Failure Determination completed on October 11, 2016 conservatively determined that the EOG would not have been able to run for its stated mission time of 30 days. This condition existed for a period of 28 days, which is greater than the TS Allowed Out of Service Time (AOT) of 72 hours. However, the Station Black Out Diesel Generator was available during this time frame.

CAUSE OF THE EVENT

The failure was determined to be low oil level found in the EOG-A radiator fan right angle gearbox due to the external relief valve pressure setting screw and the cap which goes over it being disconnected from the valve body. This allowed a pathway for oil to escape the gearbox when the EOG was running.

The radiator fan right angle gearbox oil level is checked prior to every monthly EOG run and the last time it was performed was August 31, 2016 with no problem identified during the pre-start checks. The last maintenance performed on the EOG radiator fan right angle gearbox was part of the routine examination and checks during the 2 year Preventive Maintenance (PM), which was completed on March 7, 2015. The inspection includes draining and changing the oil, performing internal inspection of the drive gears and bearings and performing backlash measurements of the drive and driven gears. However, the two (2) year PM does not perform any maintenance on ihe gearbox oil pressure relief valve. The relief pressure of 15 psig was set at the time of installation in 2000. Changes to the gearbox inspections were not updated to include any inspections or preventive maintenance for the relief valve.

The failure is attributed to minimal engagement of the pressure adjusting threaded union for the relief valve setting of 15 psig, and there is some contribution from either engine vibration or possibly human error which makes the cause indeterminate.

CORRECTIVE ACTIONS

EOG-A was declared inoperable, the relief valve was repaired, pressure tested and the pressure adjusting threaded union was staked to eliminate any risk from vibration induced motion in the future, the gearbox oil was replaced and •he EOG run for a post-maintenance test.

PNPS conducted an extent of condition review for EDG-B by performing an inspection to ensure that a common mode failure did not exist. 1 -,

The following are additional corrective actions to address this issue which are being processed through the PNPS Corrective Action Program:

1. Update station procedure 8.9.1, "Emergency Diesel Generator and Associated Emergency Bus Surveillance," to identify the plug that is used to check the oil level and visually inspect the reli~f valve to ensure the cap is appropriately aligned before and after each EOG run.

2. Incorporate a vendor manual change to capture the upgraded EDG's Cotta Transmission gear box. The gear box was updated in the 2000 time frame but the drawings/vendor manual was never updated.

3. Establish PM's for both EOG radiator fan right angle gearbox relief valves.

SAFETY CONSEQUENCES

There were no consequences to the safety of the general public, nuclear safety, industrial safety, and radiological safety due to this event.

The safety objective of the EDGs is to provide a source of on-site AC power adequate for the safe shutdown of the reactor following abnormal operational transients and postulated accidents assuming a complete loss of off-site power, as described in PNPS UFSAR.

At the time of the event, the preferred AC and the secondary AC power sources were Operable and available to perform their intended safety function. In addition, the Station Blackout AC Power Source was Functional and available as the onsite source of AC power to the emergency service portions of the Auxiliary Power Distribution System.

REPORT ABILITY

In a determination completed on October 11, 2016 it was conservatively determined that EOG-A would not have been able to run for its stated mission time of 30 days. This condition existed for a period of 28 days, which is greater than the TS Allowed Out of Service Time (AOT) of 72 hours. However, the Station Black Out Diesel Generator was available during this time frame. This issue is reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition which was Prohibited by the plant's Technical Specifications.

In addition, on September 15, 2016 EDG-B was made inoperable to perform its monthly operability run. This created a condition that could have prevented the fulfillment of the safety function of a system needed to shut down the reactor and maintain it in a safe condition, remove residual heat, and mitigate the consequences of an accident which is reportable in accordance with 10 CFR 50.73(a)(2)(v)(A), 50.73(a)(2)(v)(B), and 50. 73(a)(2)(v)(D).

The date the condition was discovered was September 28, 2016. As such, this 60-day 10 CFR 50.73 Licensee Event Report was due to the NRC Staff on November 27, 2016. This LER is being submitted late, and PNPS is addressing this through the Corrective Action Program.

PREVIOUS EVENTS

Events involving LERs where both EDGs were inoperable were reviewed. One related LER was identified and is summarized as follows:

LER 2016-001, "Both Emergency Diesel Generators Inoperable," dated June 9, 2016 stated while EDG-B was out for maintenance, EOG-A was declared inoperable due to a 130 dpm leak from the jacket water pressure boundary.

There were no other LERs involving EOG inoperability at PNPS identified in a search of the past five (5) years.

REFERENCES:

CR-PNP-2016-7443

CR-PNP-2016-9552

CR-PNP-2016-9653

CR-PNP-2016-9831

Junk NRC's "Puff Piece" News Article on Bankrupt FirstEnergy's Beaver Valley Nuclear Facility

Why did the NRC create newspaper Puff piece? Did you know how to identify Trump's" Administrative State" in any US government agency. It is when there image is more important than doing the public's interest. It is a US agency who is at war with the people.

Won't you like to hear from the NRC, "we have seriously ramped up our inspection activities based on FirstEnergy threating to shutdown Beaver Valley (and others) based on the facility being not profitable and FirstEnergy threatening declaring bankruptcy with the whole corporation." Won't raising inspection activities be conservative?

What is the agency's motives for writing this up?   

For nuclear inspectors, a 'boring' day is a perfect day

March 20, 2017 12:00 AM

By Daniel Moore / Pittsburgh Post-Gazette

Stacey Horvitz admitted she was a little excited on a recent morning, as the Beaver Valley nuclear power plant quietly loomed nearby.

She checked with her colleague, Jim Krafty, then reached for an emergency-red knob on the control panel, a sprawling bank of buttons, switches, computer monitors and lights that blinked dully. It would be a bit startling, she warned.

When she pulled it, several alarms sounded at once. Green lights turned red. Indicators showed the plant’s power generation plummeting, off-site power sources turning on, and water pumps kicking into gear.

It was such a nightmare scenario for Ms. Horvitz and Mr. Krafty that they seemed to take comfort in stressing to visiting journalists that — despite this simulated control room being a replica of the real one across the street — none of this was real.

In fact, as the two resident inspectors at the Beaver Valley plant, they spend their days ensuring there’s as little disruption as possible.

“A perfect day is a very boring day,” said Mr. Krafty, the senior resident inspector, only a little tongue-in-cheek. “Boring means 100 percent power and everything’s stable.”

The job of a nuclear inspector is immensely important. Employed by the U.S. Nuclear Regulatory Commission, they are the public’s eyes and ears at the one hundred or so nuclear power plants across the country.

The NRC launched the inspector program in 1978 — just prior to the 1979 accident at Three Mile Island in Dauphin County — to improve the agency's oversight by being able to independently verify the performance of plant operators and equipment.

Although U.S. nuclear plants have not suffered a breakdown of Three Mile Island magnitude since, inspectors address plenty of issues that would otherwise go unnoticed by reviewing equipment, reading paperwork and, occasionally, responding to an error known as a “safety-significant event.”

The Beaver Valley inspectors, like everyone else, begin their day by passing through security at the 1,800-megawatt nuclear plant, which is owned by Akron, Ohio-based FirstEnergy Corp. and sits on 453 acres along the Ohio River in Shippingport.

The inspectors get a first status update on the plant by looking over the operators’ logs, Ms. Horvitz said. “We’ll read the issues they’ve identified to see if anything has safety significance,” she said. They glean more information by talking to the operators in the control room and attending daily meetings with plant management.

They then go about a routine schedule of inspections, keeping in touch with the NRC’s regional office near Philadelphia.

Each year, their work culminates in an annual review of the plant’s performance published by the NRC, which is discussed at a public town hall. This year’s meeting is Monday from 5 to 6:30 p.m. at the Shippingport Community and Municipal Building.

The NRC trains prospective inspectors for months before sending them to a plant, pairing them with other resident inspectors to learn the ropes.

The inspectors are not licensed to operate the equipment and generally stay out of the way and let the company work, they said. They do, however, need to understand the plant equipment and know how to speak the lingo.

Every nuclear plant’s control room and operations are slightly different, Mr. Krafty said. Even at Beaver Valley, where the two reactors are both manufactured by Westinghouse, there are subtle differences due to the evolving technology: The first unit came online in 1976 and the second in 1987.

Mr. Krafty, who joined the NRC in 2004, earned a bachelor’s degree in mechanical engineering from the U.S. Naval Academy and served as a submarine officer for seven years.

Ms. Horvitz joined the NRC in 2013, shortly after graduating from the University of Pittsburgh with a bachelor’s in mechanical engineering. After completing the NRC’s 18-month training program, she joined the regional office and this year was named a resident inspector at Beaver Valley.

Despite any natural tension between government agencies and businesses they regulate, the inspectors described the relationship the NRC has with FirstEnergy as constructive and respectful.

A big reason is the inspection program itself: While strictly prohibited from socializing or getting too close to any FirstEnergy employees, the resident inspectors are on the ground every day with the workers.

“They see us every day, which puts them more at ease,” Mr. Krafty said. “They know we’re not there to make issues. We’re there to identify issues when they occur.”

“We can disagree,” he added, “but we can be professional about it.”

In recent years, Mr. Krafty said, inspectors have been involved in a number of incidents on a scale of importance: In March 2015, a security officer placed an explosives detector in service without noticing an out-of-service sign; in April 2015, a water pump failed, forcing the plant to temporarily shut down; in January of this year, a false fire alarm occurred in one of the reactor containment buildings.

Incidents are graded on four tiers of emergency. For an “unusual event” — declared by the NRC for January’s false fire alarm — is the lowest of four levels of emergency classification, for problems that “indicate a potential degradation of the level of safety of the plant.”

Though tasked with alerting the public of flaws, they insist nuclear power is safe and clean. Ms. Horvitz was surprised that a good chunk of Americans — nearly 1 in 3 in 2016, according to public opinion polls — oppose nuclear power.

“If people were allowed to come in and observe all of this, they would see the great lengths they go to ensure safety,” Mr. Krafty said.

Ms. Horvitz added, “If I didn’t think it was safe, I wouldn’t be here.”

Here below expresses the real financial condition of Beaver Valley and FirstEnergy.

Fate of Beaver Valley nuclear plant hinges on subsidies

Excerpts
(March 20, 2017) PITTSBURGH (AP) — One way or another, come next year, FirstEnergy Corp. is getting rid of the Beaver Valley nuclear power station.
Either the Ohio-based company will shut down the 1,800-megawatt plant, two decades ahead of schedule, or it will sell it to another operator. The latter option is a nonstarter unless something — aka someone, aka legislators in Pennsylvania and Ohio — intervenes to give nuclear energy a boost.
The Beaver County nuclear plant and two others in Ohio share the same chopping block as about a dozen fossil fuel plants in FirstEnergy’s portfolio across several states where electricity generation is not directly supported by ratepayers.
The primary reason why nuclear is in trouble is cheap, plentiful natural gas.
Nuclear plants don’t ramp up or down with demand. They’re steady workhorses, running when it’s economical as well as when it isn’t and providing a backbone to the electric grid. In the U.S., about 20 percent of electricity comes from nuclear power.
In Pennsylvania, which ranks second in nuclear power production in the nation, it’s closer to 35 percent.
But the price of electricity is determined by a regional wholesale market each day. Power plants offer to produce power at various prices and their offers are accepted from the lowest to higher until the demand for electricity is met.
The price offered by the last plant in that line becomes the price for all plants called on to produce power.
More often than not, the price is set by a plant that runs on natural gas. As the price of that fuel has fallen over the past several years, the price of electricity on the grid has fallen as well.
That dynamic, along with regulatory costs and lower electricity demand overall, has hurt not only nuclear plants but coal plants as well.
Last month, FirstEnergy reported a $9.2 billion impairment of its competitive generation business, erasing all but $1.5 billion of the value of its three nuclear plants and many of its fossil fuel assets. The debt associated with these plants far exceeds their current value, Mr. Jones said last month, so one of the options the company is exploring is bankruptcy protection.
The write-off is the latest step in FirstEnergy’s strategy to untangle its business from unregulated generation and focus solely on utility and transmission businesses, which are supported by ratepayers. The company announced in November that it would seek to sell or close down its unregulated plants…

New Junk Plant Watts Bar 2 is a Lemon

So two scrams in three days. These guys got serious safety cultures problems and a very poor initial startup record...

Heading for a 95001?

Power Reactor	Event Number: 52630
Facility: WATTS BAR Region: 2 State: TN Unit: [ ] [2] [ ] RX Type: [1] W-4-LP,[2] W-4-LP NRC Notified By: DAMON FEGLEY HQ OPS Officer: KARL DIEDERICH	Notification Date: 03/23/2017 Notification Time: 02:48 [ET] Event Date: 03/23/2017 Event Time: 00:14 [EDT] Last Update Date: 03/23/2017
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(iv)(A) - VALID SPECIF SYS ACTUATION	Person (Organization): MIKE ERNSTES (R2DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
2	N	Y	16	Power Operation	3	Startup

Event Text

AUTOMATIC START OF AUXILIARY FEED WATER "On March 23, 2017, at 0014 EDT, Watts Bar Nuclear Plant Unit 2 (WBN2) experienced an unplanned trip of both Turbine Driven Main Feed Pumps (TDMFP) following a loss of Main Condenser Vacuum. The trip of both TDMFPs caused an automatic start of both Motor Driven Auxiliary Feed Water Pumps and the Turbine Driven Auxiliary Feed Water Pump. [The] cause of the loss of Main Condenser Vacuum is currently under investigation." The plant was performing a normal startup, and had just synced the main generator to the grid. Subsequent to the event, the plant was transitioned to Mode 3 by inserting all rods with a manual trip. Decay heat is being removed via the atmospheric relief valves. Unit 1 remains in Mode 5 for a refueling outage. The licensee has notified the NRC Resident Inspector.

Power Reactor	Event Number: 52625
Facility: WATTS BAR Region: 2 State: TN Unit: [ ] [2] [ ] RX Type: [1] W-4-LP,[2] W-4-LP NRC Notified By: JOHN TUITE HQ OPS Officer: NESTOR MAKRIS	Notification Date: 03/20/2017 Notification Time: 10:17 [ET] Event Date: 03/20/2017 Event Time: 08:13 [EDT] Last Update Date: 03/20/2017
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL 50.72(b)(3)(iv)(A) - VALID SPECIF SYS ACTUATION	Person (Organization): MIKE ERNSTES (R2DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
2	M/R	Y	91	Power Operation	0	Hot Standby

Event Text

MANUAL REACTOR TRIP AS A RESULT OF SECONDARY PLANT TRANSIENT "On March 20, 2017 at 0813 EDT, Watts Bar Nuclear Plant (WBN) Unit 2 operations personnel manually tripped the plant from approximately 91 percent power based on lowering steam generator levels. Prior to the plant trip, the 2A Hotwell pump tripped at 0758 EDT and the 2C Condensate Booster Pump subsequently tripped at 0802 EDT. Operations personnel commenced to lower plant power after the 2A Hotwell pump trip in an attempt to maintain steam generator levels, but were unable to recover level and manually tripped the unit. "All control rods fully inserted and all automatically actuated safety related equipment operated as designed. At 0905 EDT, operations personnel exited the emergency operating instructions after the plant was stabilized. The cause of the event is under investigation. "This event is reportable to the NRC within four hours under 10 CFR 50.72(b)(2)(iv)(B) as a result of the actuation of the Reactor Protection System and in eight hours under 10 CFR 50.72(b)(3)(iv)(A) as a result of actuation of the Auxiliary Feedwater system. "The licensee notified the NRC Resident Inspector."

Junk Plant Grand Gulf New Inspection Report: No Violations.

Everyone is waiting for the special inspection report.

The new inspection report indicates continued profound weakness in the organization. Remember, the inspectors told me the plant has been having leading industry experts coming in and out of the site. Was it enough to turn around the organization...  

IR 05000416/2017009; 01/17/2017 – 02/17/2017; Grand Gulf Nuclear Station; Integrated

Inspection Report.

Inspection Scope
The inspectors observed simulator training for operating crews. The inspectors assessed the performance of the operators and the evaluators’ critique of their performance.
• January 19, 2017, the inspectors observed “Just-In-Time” simulator training for an operating crew which consisted of implementation of the startup integrated operating instruction.
• January 21, 2017, the inspectors also observed a directed learning activity for a shift manager which focused on a weakness identified during high intensity training.

The inspectors also observed portions of three emergent work activities that had the potential to affect the functional capability of mitigating systems and/or to impact barrier
integrity:
• January 27, 2017, the reactor core isolation cooling motor operated valve inoperable/power loss annunciator illuminated; the licensee stopped withdrawing control rods and performed immediate troubleshooting of thirteen isolation valves prior to verifying the capability of the reactor core isolation cooling system to
perform its function.
• January 28 – 29, 2017, the intermediate range monitor C failed; the licensee stopped withdrawing control rods and performed immediate troubleshooting that revealed a damaged cable.
• January 31 – February 3, 2017, the local power range monitor inputs to the 3D Monicore program failed to transmit data such that safety limits could be readily verified; the licensee stopped withdrawing control rods, maintained power below 21.8 percent, performed troubleshooting, and ultimately replaced the computer system.

Problem Identification and Resolution (71152)

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensee’s corrective action program. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution.

The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensee’s

problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Annual Follow-up of Selected Issues

a. Inspection Scope

On February 8, 2017, the inspectors completed a review of Grand Gulf Nuclear Station’s recovery plan, specifically focused on the restart plan corrective actions and operator high intensity training. Grand Gulf Nuclear Station performed a technical specification required shutdown on September 8, 2016, to address an issue with the residual heat removal pump A. During the shutdown, the licensee had two human performance errors in the operations department. On September 27, 2016, Grand Gulf Nuclear Station plant management notified the NRC of their intent to delay start-up of the plant, following the

forced outage, to implement corrective actions to assess and resolve operational performance concerns (See Preliminary Notification PNO-IV-16-003, Agencywide Documents Access and Management System (ADAMS) Accession No. ML16273A330).

b. Observations and Assessments

1. Restart Corrective Actions

• The inspectors reviewed the licensee’s restart plan, dated January 4, 2017, and focused on the corrective actions that the licensee had designated as, “Actions required for restart.” Of the nine corrective actions with this designation, the inspectors concluded that four were satisfactorily completed, four had received due date extensions that extended beyond the date of the restart without documented justification, and one was closed without documentation demonstrating that the intent of the corrective action was met.

The four due date extended corrective actions were centered on performing external assessments/benchmarking to ensure that normal and off-normal procedures were up to industry standards. The actions were also to address benchmarking in the area of immediate operator actions. These corrective actions were identified because inadequate procedures and operator actions played a significant role in the events leading up to the decision to stay shutdown for over four months.

Following the team’s questions, the licensee provided written discussions to be documented in the corrective actions that justified the due date extensions. In addition, the licensee was able to demonstrate that the corrective action which was closed without documenting that the intent had been met was actually

accomplished through another corrective action. They performed out-of-the-box evaluations (OBE’s) with first line supervisors in the maintenance department which met the intent of the closed corrective action.

The inspectors assessed the licensee’s problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions

and that these actions were adequate to correct identified weaknesses in operator fundamentals and station weaknesses.

2. Roles and Responsibilities

• The inspectors noted weaknesses in the outage control center’s precision, rigor, and leadership. The inspectors did not observe the outage control center driving completion of work items, and instead noted a more reactive mode of operation.

• The team noted that the operations manager occasionally stepped outside of his broader oversight role and provided specific guidance on the performance of a procedure to answer the questions of the at-the-controls operator. The inspectors concluded this was, more appropriately, the responsibility of the control room supervisor.

3. Communications

• The inspectors observed that three way communication in the control room and the field has improved significantly.

• The inspectors noted that pre-job briefs tended to be lengthy, unfocused, and unengaging. For instance, reading a procedure from start to finish was not uncommon, and the level of engagement by the operators diminished significantly after a few minutes.

• The inspectors observed that communications between the outage control center, the control room, and the in-the-field crews were not consistent, and this resulted in multiple miscommunications. On numerous occasions, while trying to ascertain status or schedule of activities, neither the shift manager nor the outage control center could provide an accurate answer.

• The inspectors observed that control room log entries lacked detail which made it difficult for an independent reviewer to assess the events reflected in the entries.

4. Procedure Use and Adherence

• During the inspection, the team observed activities that involved the operations, maintenance, and radiation protection departments. The team observed that procedure use and adherence was generally improved and that discrepancies or ambiguities in procedural steps were addressed by stopping and involving supervisors to get the problems resolved.

5. Operator Fundamentals

• The inspectors observed that the high intensity training has had a substantial impact on the operating crews, and it appears that the new higher standards are being applied throughout the operations organization. The team observed many activities in the field, which involved licensed and non-licensed operators, and directly observed the new standards in use.

• The inspectors observed operators being engaged and deliberate when manipulating controls in the control room; the operators discussed the action, the expected outcome, and verified the desired outcome following manipulations.

6. Training for Other Departments

• The inspectors noted that the licensee invested significant resources in high intensity training and improving operator fundamentals, standards, expectations, and procedures for the operations department. However, the inspectors noted

that the licensee invested fewer resources in improving the performance of the maintenance department, and the team noted that very little emphasis was placed on training, procedure quality, and setting standards and expectations in the engineering, security, chemistry, and radiation departments.

These activities constituted completion of one annual follow-up sample, as defined in Inspection Procedure 71152.