Susquehanna: First Private Nuke Plants in the USA

Nuke plants are normally owned by public utility companies. Is the Susquehanna facility the first private nuclear plant in USA. Public

House of Cards: Raymond Tusk

At the turn of the century, Clayton West expanded its nuclear business to Asian markets, a region that relied heavily on smog inducing coal power. China was the primary, and largest project of the firm's global expansion. China was also in the middle of political revolution, from communist ideals to managed capitalism. The Chinese's government's exit from business provided the conditions for Clayton West to secure a dominant market share in China's infant, but exponentially growing public economy.
By 2005, Clayton West's market cap had increased to an astounding US$90 billion, 30% of which was owned by well grounded CEO, Raymond Tusk.
In 2013 and with the 20-yr veteran Tusk at the head, Clayton West reached a market cap of US$150 billion USD, making it the largest nuclear power producer in history. As of 2014, Raymond Tusk has an estimated net worth of US$42.5 billion. 

utilities have the deep well of the pockets in the ratepayers. What happens if they have a big meltdown and lots of off site release? Who pays? Will there be less transparency? These plants are grossly obsolete dogs.

I think Nuke plant ownership with the public utilities has been a slow motion fifty year ongoing train wreck.

I think private ownership would be better.

I think government ownership with a fleet of new plants would be best...it is a unique form of energy production.

Nuclear license transfer paves way for Talen Energy to go private

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By Kurt Bresswein | For lehighvalleylive.com The Express-Times
Email the author | Follow on Twitter
on December 02, 2016 at 6:27 AM, updated December 02, 2016 at 8:28 AM

                      

Allentown-based Talen Energy Corp. is cleared for sale to affiliates of Riverstone Holdings LLC, taking the competitive electricity generation company private.

Seen in an undated photo provided by PPL Corp., the Susquehanna Steam Electric Station is in Salem Township, Luzerne County, Pennsylvania, about seven miles north of Berwick and about 50 miles northwest of Allentown. (Courtesy photo | For lehighvalleylive.com)

 

The final regulatory approval on the deal came Wednesday, when the U.S. Nuclear Regulatory Commission approved transfer of the operating licenses for both reactors at the Susquehanna Steam Electric Station in Luzerne County.
Portfolio companies of Riverstone are taking control of the licenses from Talen as part of the acquisition. The transfer applies to licenses for Susquehanna's Units 1 and 2 boiling water reactors as well as the dry cask spent fuel storage installation at the plant in Salem Township, outside Berwick.
The plant is operated by Talen subsidiary Susquehanna Nuclear LLC, the 90 percent owner of the facility. The transfer does not affect the remaining 10 percent held by Allegheny Electric Cooperative Inc.
"The proposed indirect transfer of control is not expected to change Susquehanna Nuclear's role as the plant operator, its principal officers, managers or staff or ... the day-to-day management and operation of the units," the NRC says in a news release. "No changes will be made to the units or their licensing bases as a result of the transfer."

Junk Engineer At Indian Point

This is a result of political campaign contribution. Will the NRC validate this new model. It just a paperwork or computer engineering model. These kind of models are highly susceptible to corruption. They need to do at shutdown system full flow testing with the check valve pinned open to see if they have enough flow at worst condition. You notice in initial plant design there is no mention and testing with a open check valve. You would need a indicator that a check valve is full open.

!!!!! THIS EVENT HAS BEEN RETRACTED. THIS EVENT HAS BEEN RETRACTED !!!!!
Power Reactor	Event Number: 52254
Facility: INDIAN POINT Region: 1 State: NY Unit: [2] [ ] [ ] RX Type: [2] W-4-LP,[3] W-4-LP NRC Notified By: CHRIS HASSENBEIN HQ OPS Officer: JEFF HERRERA	Notification Date: 09/21/2016 Notification Time: 09:20 [ET] Event Date: 09/21/2016 Event Time: 02:21 [EDT] Last Update Date: 11/18/2016
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(D) - ACCIDENT MITIGATION	Person (Organization): PAUL KROHN (R1DO)

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

Event Text

DISCHARGE CHECK VALVE FAILURE TO SEAT CAUSES TRIP OF COMPONENT COOLING WATER PUMP "At 0221 [EDT] on 9/21/16, Operators at Unit 2 Secured the 21 Component Cooling Water (CCW) Pump for planned maintenance while 22 and 23 CCW pumps were in operation. When the 21 pump was secured, the discharge check valve failed to seat. This resulted in a low system pressure and reverse rotation of the 21 CCW Pump due to the discharge of the 22 and 23 CCW pumps to a common header. When system pressure dropped below 107 psig the 21 CCW pump received an auto start signal. Due to the reverse rotation, the 21 CCW pump tripped on overcurrent. Reactor Operators directed Field Operators to manually shut the 21 CCW Pump discharge valve. The 21 CCW pump Discharge Valve was closed at 0223 [EDT]. This action was successful in stopping the reverse flow and restoring system parameters. During this two minute period the CCW system was declared inoperable and LCO 3.0.3 was entered. Unit 2 exited LCO 3.0.3 at 0223 [EDT] after observing system pressure and flow return to normal. The declaration of inoperability on the CCW system is considered a Loss of Safety Function for purposes of reporting under 50.72(b)(3)(v)(D). There was no reduction in power while in LCO 3.0.3 and no other issues arose." The Licensee notified the NRC Resident Inspector. The Licensee notified the Public Service Commission. * * * RETRACTION FROM CHARLES ROKES TO HOWIE CROUCH AT 1108 EST ON 11/18/16 * * * "Indian Point Unit 2 is retracting the 8-hour non-emergency notification made on September 21, 2016, at 0920 EDT (EN#52254). The notification on September 21, 2016, reported a safety system functional failure (SSFF) as a result of declaring the Component Cooling Water System (CCW) inoperable due to failure of the 21 CCW pump discharge check valve (761C) to close. This condition was discovered during planned maintenance after securing the 21 CCW pump while the 22 and 23 CCW pumps were in operation. When the 21 CCW pump was secured, the discharge check valve failed to seat. This resulted in a low system pressure and reverse rotation of the 21 CCW pump due to the discharge of the 22 and 23 CCW pumps to a common header. Condition was reported as a safety system functional failure (SSFF) under 10 CFR 50.72(b)(3)(v)(D). "After further investigation of the condition, a revised calculation was prepared for the CCW hydraulic model which is used to analyze CCW system performance for normal and DBA [design basis accident] modes of operation and documented in a calculation. The new calculation included the as-found condition of the 21 CCW pump discharge check valve failure to seat. Based on the results of the new calculation, the CCW system is capable of performing its design basis heat removal function during a design basis accident. Calculated flow rates with CCW aligned for Post-LOCA recirculation demonstrates that with failed open check valve 761C, the 22 CCW pump and 23 CCW pump have adequate NPSH margin, are operating below analyzed pump run out and deliver flow to the CCW system that is significantly greater than the flow required for post-LOCA recirculation. Therefore the CCW system was operable and a safety system functional failure (SSFF) did not occur as a result of failed open 21 CCW pump discharge check valve 761C." The licensee has notified the NRC Resident Inspector and will be notifying the New York Public Service Commission. Notified R1DO (Bickett).

New Earthquake and Tsunami at Fukushima

"This quake occurred about 75 miles southwest of the devastating 2011 Tohuku quake and is on a different fault line, a U.S. Geological Duty Seismologist told NPR's Chris Joyce."

NRC's Public Documement system (ADAMS) Down Again

Today, just started...

Increasing unreliability...

Junk "Shutdown" Grand Gulf: Upper Management Allowed Operation's Department to Spin Wildy Out of Control

Entergy's story is they voluntarily shutdown during post outage due to "operation department" problems. Here we see the NRC severely pressuring Grand Gulf to get their operations department together way prior to this disgusting event.

One wonders how long the NRC was seeing this?

Follow Up Inspection for Three or More Severity Level IV Traditional Enforcement Violations in the Same Area in a 12-Month Period 

a. Inspection Scope The inspectors performed Inspection Procedure (IP) 92723, “Follow Up Inspection for Three or More Severity Level IV Traditional Enforcement Violations in the Same Area in a 12-Month Period,” based on the results of the NRC’s annual review of station performance as documented in the 2015 assessment letter dated March 2, 2016, (ML16061A361).  In 2015, the NRC issued the following seven Severity Level (SL) IV traditional enforcement violations in the area of impeding the regulatory process:

• NCV 05000416/2015002-03, “Failure to Update the Final Safety Analysis Report after the Extended Power Uprate”

• NCV 05000416/2015007-05, “Failure to Maintain a Safety-Related Cable Tray Overfill Analysis Record”

• NCV 05000416/2015007-07, “Failure to Update the Final Safety Analysis Report”

• NCV 05000416/2015007-08, “Incomplete and Inaccurate Response to NRC Bulletin 88-04”

• NCV 05000416/2015007-09, “Failure to Obtain a License Amendment for Use of Probabilistic Methods to Evaluate Tornado Missile Hazards”

• NCV 05000416/2015008-04, “Failure to Make Required Event Notification”

• NCV 05000416/2015004-03, “Failure to Make a Required Eight-Hour Report for Loss of Safety Function”

The inspectors reviewed the licensee’s cause evaluation and corrective actions associated with these issues in order to determine whether the licensee’s actions met the IP 92723 inspection objectives to provide assurance that: (1) the cause(s) of the violations are understood by the licensee, (2) the extent of condition and extent of cause of the violations are identified, and (3) licensee corrective actions to the violations are sufficient to address the cause(s).

What a horrible mess...how deep in the hole will they allow a plant go. I worry about the NRC...will allow numerous plants to decay into having capacity factor problems and being unsafe. There will be numerous plants sitting on the edge of being unsafe. The totality of this will be to keep the NRC to be very busy with putting out small fires, all this work will numb and over overwhelm the involved inspectors.

IR 05000416/2016003; 07/01/2016 - 09/30/2016, Grand Gulf Nuclear Station; Equipment Alignment, Heat Sink Performance, Problem Identification and Resolution.

The inspection activities described in this report were performed between July 1, 2016, and September 30, 2016, by the resident inspectors at Grand Gulf Nuclear Station and inspectors from the NRC’s Region IV office and other NRC offices.  Four findings of very low safety significance (Green) are documented in this report.  Three of these findings involved violations of NRC requirements.  Further, inspectors documented a licensee-identified violation of very low safety significance in this report.  The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red), which is determined using Inspection Manual Chapter 0609, “Significance Determination Process.”  Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, “Aspects within the Cross-Cutting Areas.”  Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy.  The NRC’s program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, “Reactor Oversight Process.” Cornerstone:  Initiating Events

• Green.  The inspectors identified a finding for the licensee’s failure to aggressively and fully communicate an operational decision-making instruction implementation action plan, particularly the trigger points and those actions if trigger points are exceeded, to the appropriate operations shift personnel via operations management in accordance with Procedure EN-OP-111, “Operational Decision-Making Issue Process.”  Specifically, on July 3, 2016, Grand Gulf Nuclear Station operations management created an operational decision-making instruction, but did not communicate to onshift operators the trigger points and actions associated with uncontrolled power oscillations that occurred on June 17, 2016.  The licensee implemented immediate corrective actions by communicating the  operational decision-making instruction trigger points to all onshift operators, as well as creating an offnormal event procedure.  This finding was entered into the licensee’s corrective action program as Condition Report CR-GGN-2016-06032.      The failure to follow Procedure EN-OP-111 to aggressively and fully communicate an operational decision-making instruction implementation action plan, particularly the trigger points and those actions if trigger points are exceeded, to the appropriate operations shift personnel via operations management was a performance deficiency.  This performance deficiency is more than minor, and therefore a finding, because it is associated with the human performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.  Specifically, operations management did not communicate operational decision-making instruction trigger points and actions to ensure appropriate operator response to limit the liklihood of events that upset plant stability, similar to the reactor pressure and power oscillations that occurred on June 17, 2016.  Using Inspection Manual Chapter 0609, Appendix A, “The Significance Determination Process (SDP) for Findings At-Power,” and Inspection Manual Chapter 0609, Appendix A, Exhibit 1, “Initiating Events Screening Questions,” the inspectors determined that the finding was of very low safety significance (Green) because the finding did not cause a reactor trip. 

The inspectors determined that the finding has a change management cross-cutting aspect within the human performance area because licensee management failed to use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority.  Specifically, the licensee failed to use the operational decisionmaking instruction process effectively such that the operational decision-making instruction was communicated and could be implemented as intended [H.3].  (Section 4OA2.2.3) 

 Cornerstone: Mitigating Systems • Green.  The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” which states, in part, “conditions adverse to quality are promptly identified and corrected.”  Specifically, prior to April 2012, the licensee did not correct identified deficiencies affecting work order instructions and acceptance criteria to perform surveillance requirements associated with safety-related fuel pool cooling and cleanup heat exchangers.  In response to this issue, the licensee revised the associated procedure to provide appropriate quantitative and qualitative acceptance criteria.  This finding was entered into the licensee’s corrective action program as Condition Report  CR-GGN-2016-07257.   The failure to promptly correct procedures and work order instructions used to perform program testing of safety-related heat exchangers was a performance deficiency.  Specifically, the licensee did not promptly correct identified inadequate work order instructions or acceptance criteria to perform surveillance requirements associated with safety-related fuel pool cooling and cleanup heat exchangers from April 2012 until September 30, 2016.  The inspectors determined that it was reasonable for the licensee to be able to foresee and prevent occurrence this deficiency.  This performance deficiency is more than minor, and therefore a finding, because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., fuel damage).  Specifically, the inspectors concluded that without appropriate quantitative and qualitative acceptance criteria, the availability, reliability, and capability of the fuel pool cooling and cleanup heat exchangers would not be effectively ensured through the performance of surveillance requirements.  The inspectors evaluated this finding using NRC Inspection Manual Chapter 0609, Attachment 0609.04, “Phase 1 – Initial Screening and Characterization of Findings.”  The inspectors determined that the finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of a safety function of a system or a single train for greater than its technical specification allowed outage time, and did not screen potentially risk significant due to external events.  The finding has a crosscutting aspect in the area of human performance, documentation, because the licensee did not create and maintain complete, accurate, and up-to-date documentation for the safety-related heat exchanger testing program [H.7].  (Section 1R07) • Green.  The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” for failure to promptly identify a condition adverse to quality.  Specifically, operations personnel failed to identify oscillations in the reactor core isolation cooling transmitter logic system during technical specification surveillance control panel walk-downs.  This resulted in an automatic isolation of the reactor core isolation cooling system from its steam supply.  Approximately six hours after the isolation, maintenance personnel performed a flow transmitter system fill and vent, and the system was returned to an operable condition.  This finding was entered into the licensee’s corrective action program as Condition Report CR-GGN-2016-03070.     

The failure to promptly identify oscillations in the reactor core isolation cooling transmitter logic system was a performance deficiency.  This performance deficiency is more than minor, and therefore a finding, because it is associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.  Specifically, operations personnel failed to identify oscillations in the reactor core isolation cooling transmitter logic system, which resulted in an isolation and unavailability of the reactor core isolation cooling system.  Using Inspection Manual Chapter 0609, Appendix A, “The Significance Determination Process (SDP) for Findings At-Power,” and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, “Mitigating Systems Screening Questions,” the inspectors determined that the finding is of very low safety significance (Green) because it was not a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; did not represent a loss of system and/or function; did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-ofservice for longer than their technical specification allowed outage time; and did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensee’s maintenance rule program.

In addition, the inspectors determined that the finding has a challenge the unknown crosscutting aspect within the human performance area because the licensee failed to stop when faced with uncertain conditions and evaluate and manage risk before proceeding.  Specifically, when performing multiple sets of operator control panel walk-downs, which should have resulted in the identification of oscillations in the reactor core isolation cooling transmitter logic system, the operators failed to recognize and correlate that the small oscillations were an abnormal system condition and could lead to a reactor core isolation cooling system isolation [H.11].  (Section 1R04)

• Green.  The inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4.1.a for the failure to establish a procedure for combating malfunctions of the reactor pressure control system.  Specifically, on June 17, 2016, operators combated a malfunction in the reactor pressure control system associated with an unexpected turbine stop valve closure without having appropriate procedures.  The licensee implemented immediate corrective actions by creating a standing order that gave clear guidance on how to control issues that cause oscillations, and has since created an offnormal event procedure for reactor pressure control system malfunctions.  This finding was entered into the licensee’s corrective action program as Condition Report CR-GGN-2016-04834.       The failure to establish a procedure for combating malfunctions of the reactor pressure control system was a performance deficiency.  This performance deficiency is more than minor, and therefore a finding, because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.  Specifically, operators were combating a malfunction in the reactor pressure control system associated with an unexpected turbine stop valve closure without having a procedure.  As a result, the operators were unable to reconcile the pressure control malfunction, did not manually scram the reactor, and ultimately caused an automatic reactor scram.  Using Inspection Manual Chapter 0609, Appendix A, “The Significance Determination Process (SDP) for Findings At-Power,” and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, “Mitigating Systems Screening Questions,” the inspectors determined that the finding resulted in themismanagement of reactivity by operators and required an evaluation using Inspection Manual Chapter 0609, Appendix M, “Significance Determination Process Using Qualitative Criteria.”  A senior reactor analyst performed an evaluation to bound the increase in core damage frequency of the finding.  Based on the results of this evaluation, the final significance of the finding was determined to be very low safety significance (Green).

In addition, the inspectors determined that the finding has an identification cross-cutting aspect within the problem identification and resolution area because the licensee failed to identify issues completely, accurately, and in a timely manner in accordance with the program.  Specifically, the licensee failed to identify that they were missing an offnormal event procedure for malfunctions of the reactor pressure control system following a 2015 half scram that occurred while conducting the same testing as that which led to this event  

[P.1].  (Section 4OA2.2.2)  Licensee-Identified Violations
 A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors.  Corrective actions taken or planned by the licensee have been entered into the licensee’s corrective action program.  This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.  

Junk plant Hope Creek: Still at 89%

Update Nov 22

Congrats Hope Creek with finally being at full power. How long will it hold.

***So they started up on Nov 10th, eleven days later they are not at 100%. Jumping around from 60% to 90% power since start-up... 

This is a very troubled three unit site. The second largest nuke facility in the USA?

Countries Heroin Addict Dumping Into USA

Do you know what patient dumping is. This could debilitate us. Do you have a idea how costly this is. I guess Puerto Rica is a territory of the USA needing no visa. Do you see how the drug cartels in the USA would use these extraordinary vulnerable people. It is illegal to patient dump and I would call these people being so sick patients.

Puerto is bankrupt and begging us of money...

I would declare war on Puerto Rica and embargo all funding, dictate all Puerto Ricans need a visas
and IDS...to stop this and have the country regain control of their drug gangs.

All heroin addicts need to be emediately deported back to their country!!!    

Philly begins to look into the dumping of Puerto Rican addicts

Updated: November 18, 2016 — 10:51 PM EST

       

"It's sad because people are in need," Mayor Kenney said. "And these are Americans. They're here, and we're going to find a way to help them."

A spokeswoman for the mayor said the city was deeply concerned with the way addicts are given one-way tickets to Philadelphia and deposited into unregulated recovery houses.

"The police are looking at this case to see where intervention would be effective," she said. "They're looking at Air Bridge in terms of what's happening in these recovery houses.

"We're as distraught and upset as everyone else about the story."

Some intervention has already begun.

Police and building inspectors converged Monday on a Kensington drug-recovery house that had been the home of a Puerto Rican man who said he had been duped into coming to Philadelphia for addiction treatment he never received. The man, Kelvin Aldarondo, 21, of Aguadilla, P.R., was profiled in the Nov. 13 article.

Officials found 26 men living in the three-story, four-bedroom house, although occupancy laws allow no more than 20 to sleep there, city inspectors said. It was not clear how many had come from Puerto Rico, police said.

It also appeared the men were locked in, which violates fire laws, police said. And the house, which serves food paid for by the occupants' food stamps, lacks a current food license, inspectors said...                                                                                                                                             

Junk Plant Hope Creek: Delayed Getting TO 100% After Startup

Hope Creek started up on Nov 10...they are only at 89% power last night. What a dog!

Junk Plant Grand Gulf: Nuclear Industry Becoming Increasingly Chaotic

Update Nov 18

SOB, I am a prophet. Why aren't people paying me millions of dollars? Did I predict they would be shutdown over operation's department problems? I believe the long stream of shutdowns, down powers and plant chaos had exhausted and numbed the operations department.

"These poor control room operators. Like I said, this is how the engineers and NRC screws the licensed operator with setting up this plant with poorly maintained equipment."

Junk Plant Grand Gulf: Delay Startup to Fix Safety Culture

Originally published on 7/20

Update 7/21

This is way cool. Grand Gulf just started up last night. It was about a 21 day preventable outage.  I'll be watching these guys closely now.

***It's like a junk unreliable 3 year old $100,000 dollar Cadillac CTS-V. It is now the largest single plant in the USA?*** 

*Call me stupid, but why has Grand Gulf been down in the extreme of the summer? Its where they can make the most money? But they are a regulated plant. They have been down for weeks. You don't have a scheduled outage during the middle of the southern summer.
Of course, its a increasingly unreliable Entergy plant. It's Mississippi's only nuclear plant.  

Basically for months or more River Bend and Grand gulf has been alternating each other with scrams and power restriction. It is a disgrace for the industry. Normally a plant gets funded to maximize capacity factor. Can they make more money someway by funding a plant to a 90% capacity factor?

Updated: What is this saying below?

*Scram 6/17/2016-6/19

*Scram 7/30-?

6/17 scram: what a horrible month for Grand Gulf. Basically two scrams 13 days apart. What a industry embarrassment. Look at all the big component not properly maintained...failing and causing multiple scams in a short period of time. The last scam causing a 20 day unscheduled outage. More than one big component failing in one scram. These poor control room operators. Like I said, this is how the engineers and NRC screws the licensed operator with setting up this plant with poorly maintained equipment. Guys, this in the future of the industry in front of us. They are wrecking the nuclear industry!!!

AUTOMATIC REACTOR SCRAM DURING TESTING

"During planned stop and control valve testing, two main turbine high pressure stop valves closed instead of the expected one (stop valve 'B'). This caused the main turbine control valves, power, reactor pressure to swing and a division 2 half SCRAM. Control rods were inserted to reduce power and the power swings. At 0257 [CDT] the reactor automatically SCRAMMED. Reactor SCRAM, Turbine Trip [procedures] ONEPs and EP-2 were entered. Reactor water level was stabilized at 34 inches narrow range on startup level control and reactor pressure stabilized at 884 psig using main turbine bypass valves. No other safety related systems actuated and all systems performed as expected."

The plant is in its normal shutdown electrical lineup using normal feedwater and turbine bypass valves for decay heat removal. Reactor pressure is slowly trending down. The licensee is investigating the cause of the second stop valve shutting.

The licensee notified the NRC Resident Inspector.

6/30 scam: leading to a plus 20 day outage.

In the industry's history of loss of service or instrument air, this causes plants to spin widely out of control. It has traditionally caused very expensive plant damage. Most plants have a diesel generator air compressor stationed outside the turbine building for just this reason. It automatically starts on low air pressure and saves the asses of the control room employees. Is Entergy abandoning Grand Gulf. The normal air compressors are not maintained as safety related equipment. Basically they lost control of neutron flux shape in the core and had to scam for safety. I wonder if they just let it go without operator action what would have happened. Aren't plants design for hands off operation for the first 10 minutes of a scam?

Did they have a spare transformer on site or was one readily available? Or did they have to order one from China?  

*Oh what a disgrace, they just upgraded the plant to the tune of hundreds of millions to a billion dollars. And they got a much poorer plant reliability and capacity factor. What a junk/ drunk billion dollar nuclear plant upgrade :) 

MULTIPLE VALID SPECIFIED SYSTEM ACTUATIONS DUE TO LOSS OF SERVICE TRANSFORMER 21

"On June 30, 2016 at 1715 CDT, Grand Gulf Nuclear Station (GGNS) experienced an electrical power supply loss from Service Transformer 21 which resulted in power supply being lost to Division 2 (16AB Bus) and Division 3 (17AC Bus) ESF buses. This resulted in a valid actuation of Division 2 and Division 3 Diesel Generators on bus under voltage. They both automatically started and energized their respective ESF buses as designed.

"During this event, the loss of power to the Division 2 (16AB Bus) resulted in a Division 2 RPS bus power loss, which actuated a Div 2 RPS half SCRAM signal.

"The power loss also resulted in a loss of the Instrument Air pressure resulting in some Control Rod Scram Valves to drift open. This in turn caused the Scram Discharge Volume to fill to the point where a Div 1 RPS half SCRAM signal was initiated from Scram Discharge Volume level high on Channel 'A'. This resulted in a valid full RPS Reactor SCRAM while not critical. Instrument Air pressure was restored and the SCRAM signal was reset at 1733 CDT.

"Appropriate off normal event procedures were entered to mitigate the transient. No ECCS initiation signals were reached. All safety systems performed as expected.

"GGNS was in Mode 4, Cold Shutdown, with MSIVs closed at the time of the event. Reactor water level was maintained in the normal water level band by Control Rod Drive system throughout this event. RHR 'A' was maintained in Shutdown Cooling operation and it was not affected by this event."

The licensee notified the NRC Resident Inspector.

That is the problem with the philosophy of spending all your money on a big power uprate. Then you have to deal with all the obsolete components breakdowns you never spent money on. The typical Entergy uprate only changes out a small proportion of the components in the plant. It like throwing money away. VY and Fort Calhoun did the same thing and they had to quickly permanently shutdown because the plant then became unprofitable.   

The Grand Gulf Behemoth

In fall 2012, work was completed on the extended power uprate project at Entergy's Grand Gulf Nuclear Generating Station, near Port Gibson, Mississippi. The project increased the energy output of the plant by more than 13 percent, making the Grand Gulf Nuclear Generating Station the most powerful nuclear reactor in the United States and one of the most powerful in the entire world with a total capacity of 1443 MW.
CB&I (then The Shaw Group Inc.) won the EPC contract for the EPU project and oversaw most of the work, with the exception of the steam dryer and turbine components. The uprate of the BWR plant involved replacing the heat exchanges, main feedwater heaters, moisture separator reheaters and main transformers, as well as enhancing the plant's cooling capacity. The main generator and high-pressure turbine rotor were both replaced as well, which was completed by Siemens.
Uprates have become a popular method of expanding nuclear power in a cost effective and efficient way. According to the NRC, the regulatory body has approved uprates adding up to 6,862MW of electricity generating capacity in the United States, equivalent to constructing a handful of brand new reactors from the ground up. -Ed.

Massive Cyberattack Ongoing at the Nuclear Regulatory Commission

Update Nov 18

Adams is still dead.

This is another example of the NRC’s penchant for secrecy. How much else do they hide from us? If it is embarrassing for the agency…just burry the evidence in a deep hole so outsiders never understand. This has impaired the agency for most of the day.  Outsiders like me can’t access the NRC’s and licensee’s documents on the Adams. What about government transparency? How do you hold government employees accountable concerning spending my money? We should have gotten a complete explanation about this morning. It is extremely rude and unprofessional. What kind of government is this???  How many minutes were people attempting to connect to ADAMS and just watching that little processing clock spin around till it tripped you off the dead system.     

Completely disconnect the agency from the internet this morning (at least in Region I). Connections to internet very spotty the rest of the day.

ADAMS has been down all day. This thing must be huge?
 

Sent hordes of employees home early because no work could be done???

Is the Hinsdale NH/Brattleboro Vt Route 119 Bridge In Trouble?

Shaheen: ‘Good news’ that Sewalls Falls Bridge is open, but funding picture is the ‘bad news’

Jeanne Shaheen said the federal government’s reluctance to invest in infrastructure is at least partly to blame for the length of time it took to build the new Sewalls Falls Bridge in Concord.

Shaheen, a Democratic U.S. senator and former governor, noted at an opening ceremony of the bridge Tuesday that it was in 1994, when she was only a state senator, that she began working to replace its 1915 predecessor.

The complications that caused such a lengthy process were numerous, said state Department of Transportation spokesman Bill Boynton. There were historical and environmental implications, as well as conservation easements and funding to be attained.

But Shaheen focused on the federal funding for the project that was promised but delayed in reaching New Hampshire.

“The federal government really didn’t do what we said we were going to do at the timetable that we said we would,” Shaheen said. “It shouldn’t take that long to get this kind of a project done.”

Mayor Jim Bouley added with a smile that he had a full head of hair when the planning process began.

Bill Cass, the assistant commissioner of the state’s Department of Transportation, said his colleagues planned in 2003 that the bridge could be constructed by 2007, “but there was a little note in the margin that said it could be delayed two or three years as they worked through some of the issues.”

In the end, it was Aug. 9, 2015, before construction began, nearly a year after the historic connector between routes 3 and 132 was closed.

The federal Highway Trust Fund was healthy and growing for several decades until recently, according to the Congressional Budget Office, when spending began to outpace taxes collected on gas and other transportation-related products and activities. Between 2008 and mid-2015, the federal government had to transfer more than $65 billion from the general fund to cover highway expenses.

The start of construction on the Sewalls Falls Bridge was delayed in 2015 amid the shortfall. The city ended up cutting a deal with the state DOT, which administers the federal grant money, that would allow Concord to start building and be reimbursed with federal dollars when they became available, according to a Monitor report at the time. A federal grant paid for 80 percent of the $11 million project.

Shaheen visited the bridge back then and lamented that there had been 32 short-term extensions of the Highway Trust Fund in the previous six years, without the adoption of a long-term solution.

That’s the “good news, bad news” story of the bridge funding, Shaheen said Tuesday.

“I’m thrilled to be here to celebrate the good news of this story today and I pledge to you that I will continue to work on the bad news of getting those investments at the federal level,” she said, “so we can continue to see these kinds of projects move forward for the state of New Hampshire.”

The bridge opened to traffic last week. For a time before the earlier bridge closed, drivers had to take turns crossing one at a time for fear that it couldn’t accept the weights it once held.

Largest Oil Deposit Ever Found In U.S: Premian Basin/Wolfcamp Shale

What does this mean for the nukes?

USGS: Largest oil deposit ever found in U.S. discovered in Texas

USA Today Network Mary Bowerman , USA TODAY Network 8:26 a.m. EST November 17, 2016

In this May 18, 2015, file photo, more than 30 oil drilling rigs stood idle in Odessa, Texas. Ken Medlock, director of an energy-studies program at Rice University in Houston, says an assessment Tuesday, Nov. 15, 2016 by the U.S. Geological Survey that the Wolfcamp Shale in the Midland-Odessa region could yield 20 billion barrels of oil is another sign that "the revival of the Permian Basin is going to last a couple of decades."(Photo: Courtney Sacco, AP)

The U.S. Geological Survey recently discovered the largest continuous oil and gas deposit ever found in the United States, officials said Tuesday.
The agency announced that the Wolfcamp shale, located in the Midland Basin portion of Texas’ Permian Basin, contains 20 billion barrels of oil and 1.6 billion barrels of natural gas liquid.
The Permian Basin is one of the most productive oil and gas areas in the country, and more than 3,000 horizontal wells have been drilled in the Wolfcamp shale section, the agency said in a statement.
“The fact that this is the largest assessment of continuous oil we have ever done just goes to show that, even in areas that have produced billions of barrels of oil, there is still the potential to find billions more,” said Walter Guidroz, program coordinator for the U.S. Geological Survey (USGS) Energy Resources Program.
The oil is worth almost $900 billion at current prices, Bloomberg News reported.
The discovery is nearly three times larger than oil found in 2013 in the Bakken and Three Forks formations in the Williston Basin Province of Montana, North Dakota and South Dakota, according to the USGS.

President Trump and the NRC

The House and Senate is being run by the republicans. The NRC commissioners normally have five members. There is only three in there now, based on republican obstructionism of Obama. I’d remind President Trump, if a nuke plant melted down and caught in a scandal like TMI, it would eat up a tremendous amount of your administration.  Other interest would be placed in the back room.

Trump spoke very little about anything nuclear industry prior to the election.

So, President Trump will have a tremendous influence on the NRC and nuclear industry. The nuke industry and electric utilities are a very politically powerful force. These guys eat presidents and governors of all stripes by the dozens.

My great hope is he would reform our electric system.

I’d like him to commit the USA into replacing 50% of our nuclear plants in a decade with new plants…

Junk Plant Pilgrim: Leaking And Severely Deteriorated Turbine/Reactor Building Seismic Safety Seals

Update

I called back the NRC. Man, have they become responsive. So I called the second time. Talked a little, they said we are looking into it. The region 1 inspector support guy called me right back within minutes. He confirmed the NRC is looking at it with pilgrim...looking to see if it had generic implication.

I would have liked to get a call back in these first two calls saying the seismic seals are inspected on a regular bases...the last time was three years ago on such and such a date. Everything is fine. 



***Getting ready for the big inspection. Here is an important safety seal at Vermont Yankee never inspected during the life of the plant. It was discovered completely deteriorated and causing in leakage in a closed plant. It has implications at other similar plants. Do you think Entergy and the NRC covered their asses looking for this problem at other plants?

I just called the NRC inspectors at Pilgrim. I left a message inquiring about this problem at Pilgrim. I wanted to talk about water in leakage into pilgrim.

Water leak reported at Vermont YankeeBy SUSAN SMALLHEER
Rutland Herald
Wednesday, September 28, 2016

BRATTLEBORO, Vt. — Entergy Nuclear says it has found a potential source of water infiltration into Vermont Yankee’s turbine building, a problem that has cost the company more than a million dollars.

Entergy Nuclear spokesman Joseph Lynch told members of the Vermont Nuclear Decommissioning Citizens Advisory Panel that metal barriers on either side of the so­ called seismic gap between the turbine building and the reactor building were being replaced in an effort to keep groundwater from seeping into the building.

Lynch said the gap between the two buildings was created as a safety feature when Vermont Yankee was built in the event of an earthquake. But plant officials now think that a deteriorated metal barrier and its insulation is letting water into the turbine building.

He said the seismic gap was only a couple of inches wide. He said replacing that metal barrier, which is insulated with some kind of foam material, began this week, a project that is expected to take five weeks. He said the company believed that would drastically reduce water infiltration.

Currently, between 700 and 900 gallons of water a day are seeping into the turbine building. Once it reaches the building, it becomes contaminated with radioactivity.


At one point this winter, Entergy was storing the contaminated water in small portable swimming pools, but it has discontinued that practice.

In January, Entergy said 2,500 to 3,000 gallons a day were leaking into the turbine building.

On average, the company is paying $4 a gallon to dispose of the contaminated water, which is being shipped to U.S. Ecology Idaho Inc. in Grand View, Idaho. In June, the company said it had spent $1.2 million on the water problem.

Lynch told Brattleboro resident Bob Leach that the radioactivity levels in the water were so low, that the tankers full of tainted water did not even need to be placarded according to federal regulations as radioactive.

Entergy is shipping one tanker holding 5,000 gallons of contaminated water a week to the disposal site in Idaho, and it has a storage tank that holds 20,000 gallons of water to collect the tainted water.

Lynch said actions by the company to seal cracks in the building’s foundation had cut back on the amount of water coming into the building since it was first discovered in winter 2015, shortly after Vermont Yankee shut down.

The company said it believed the water had been seeping into the building all along, but once the building went ‘‘cold and dark’’ after the reactor’s shutdown, the building was no longer warm, leading to natural evaporation.

Mike McKenney of Entergy Nuclear gave the panel an update on the water intrusion problems, and said if the project started earlier in the week it likely would sharply reduce the amount of water coming into the building.

McKenney told Rep. David Deen, D­Westminster, a panel member, that he did not believe that this summer’s prolonged drought had an effect on the drop in groundwater seeping into the building.

He said the company was investigating drilling interceptor wells under the building to keep the clean water from seeping into the building, thus picking up radioactivity in the process.

Earlier this year, Entergy said it was thinking of seeking a state permit to discharge the radioactive water into its storm drain system, which in turn discharges directly into the Connecticut River. Entergy has since dropped those plans.

Entergy has said it plans to seek reimbursement from the Vermont Yankee decommissioning trust fund to cover its costs addressing the water problem.

TVA Heading To Perdition

The fixation on budget reductions is going to kill them. All these CEOs need to do is shift to natural gas to become heroes.

TVA gives top bosses record pay hike; utility's employees to share $102 million

Winning performance payments are down nearly 10 percent from previous year

November 16th, 2016 by Dave Flessner

TVA employees will have extra reason to be thankful at the Thanksgiving holiday this year with year-end bonuses being paid just in time for Black Friday sales next week.

The utility's 10,700 employees will share in $102 million of winning performance pay based upon the utility's record in the past year of achieving record high income while cutting the average price of power delivered to the 9 million people across its seven-state region.

In its year-end financial report, TVA said it met more than 80 percent of its performance goals during fiscal 2016.

The winning performance payments average more than $9,532 per worker, but most hourly employees will get only a fraction of that amount and the specific payments also vary according to what individuals are paid and in what division they work within at TVA.

The winning performance payments are down nearly 10 percent from the previous year when TVA paid a total of $113 million to 10,900 workers, or an average of nearly $10,367 per worker.

TVA officials said employees are scheduled to receive the yearly bonus checks next week, just ahead of Thanksgiving.

"We continue to set higher standards each year and, while we had a very good year in achieving most of our performance metrics, we did not fully meet all of the objectives and the winning performance payments reflect that," said Sue Collins, TVA's chief human resources officer.

Although TVA boosted its net income in the past year to a record high $1.2 billion and cut the average cost of power by 2.3 percent, TVA failed to meet its performance goals for nuclear power production with more frequent plant outages than planned.

TVA reduced the average delivered cost of its power from 7.2 cents per kilwatthour in 2011 to 6.7 cents per kilowatthour in 2016. The savings have come primarily due to cheaper fuel, but TVA also has trimmed $800 million of annual operating expenses in the past four years by cutting staff, reducing borrowing and phasing out some plants and programs.

TVA completed construction and started the Watts Bar Unit 2 reactor this year as the first new nuclear unit added to America's grid in the 21st century. But the project ended up taking more than three months longer than what was budgeted and during its completion the U.S Nuclear Regulatory Commission raised concerns about what it said was a "chilled environment" for plant workers to raise safety concerns.

The year-end payments for performance are part of the at-risk pay for TVA employees designed to encourage workers to help the federal utility achieve its goals for safety, reliability, cost and economic development.

Individual TVA employees who are not covered by labor union contracts also get annual pay raises based on their performance. Merit pay increases granted to salaried and other office workers last month averaged 2.8 percent to 3 percent, TVA spokeswoman Gail Rymer said.

Pay at the top

TVA's top bosses took home even bigger paychecks in fiscal 2016 based upon meeting most of TVA's targets.

TVA President Bill Johnson was paid a record $4.9 million in salary and performance bonuses in the fiscal year ended Sept. 30, up 7.4 percent from what he was paid in salary and bonuses the previous year. Including the value of his pension and other payments, Johnson's overall compensation in fiscal 2016 totaled $6.45 million, making him again this year the highest paid federal employee in America.

His pay and bonuses last year were more than 12 times the $400,000 salary paid to the president of the United States and 24 times the $203,700 salary for members of the president's cabinet.

But Johnson, a former Progress Energy CEO recruited to TVA four years ago, was paid in the bottom quartile of top utility CEOs in the private sector, according to pay consultants who study executive compensation. The $4.9 million paid to the TVA CEO in the past year was 40 percent below the median pay of nearly $8.2 million for 21 comparable CEOs in the utility industry surveyed by the Towers Watson consulting group.

Johnson's $950,000-a-year salary, before any performance pay, did not change in the past year, and his increase in pay came entirely from performance pay increases.

Last week, however, TVA directors agreed to boost the amount Johnson could earn next year to help bring his compensation better in line with that of other comparable utilities. The board agreed to raise the performance bonus potential for Johnson from 285 percent of his base salary of $995,000 to 305 percent of that salary in 2017.

TVA Chairman Joe Ritch said TVA must remain competitive in its compensation with other utilities and should reward managers and employees when they meet performance standards.

"We've seen enormous progress and we recognize that when you have a highly talented person or group of persons in management like we have at TVA we need to be somewhat competitive in our compensation," Ritch said. "We are still below the average pay for many of these positions, but we still want our leadership to know that we are supporting them. While compensation is not the only thing you get by working at TVA, it is a very important reflection of our belief that they should be here and stay here at least for a reasonable period of time."

Other top TVA executives also enjoyed bigger boosts in total compensation last year due to TVA's improved performance. TVA Chief Operating Officer Charles "Chip" Pardee, who is retiring from TVA next month, was paid a compensation package worth more than $3.3 million, up 12 percent from the $2.98 million in total compensation Pardee received a year ago.

Two other TVA executives are expected to earn more next year in new positions at TVA filling the vacancy created by Pardee's retirement. Last month, TVA Nuclear Chief Joe Grimes was promoted to executive vice president of generation, while Mike Skaggs, who previously headed the completion of Watts Bar Unit 2, was promoted to executive vice president of operations.

Richard Howorth, head of the board's People and Performance Committee, said the increases in executive pay reflect the top managers' success in achieving most of TVA's performance targets. If such goals had not been met, their pay would have been reduced.

"This is at-risk compensation," Howorth said last week at a TVA board meeting in Blairsville, Ga.

Income improves

Despite lower net power sales from extreme weather, reduced operating costs helped the Tennessee Valley Authority achieve its highest ever net income of $1.2 billion for fiscal year ended Sept. 30, 2016, up $122 million from 2015.

TVA reported that sales of electricity decreased by 1.5 percent for the fiscal year, as compared to the prior year. The Tennessee Valley region experienced the second mildest winter of the last 55 years, only partially offset by the warmest summer of that same period.

Revenues from the sale of electricity decreased by $386 million in fiscal year 2016, as compared to the prior year, primarily due to lower fuel cost recovery revenues, as well as lower sales volume driven by weather.

"It was a strong year for TVA employees — they met goals and objectives and delivered results for the Tennessee Valley financially, operationally and in our relationships with customers and other stakeholders," Johnson said. "In 2016, our fuel and purchased power costs were nearly a billion dollars less than in 2012. This was due primarily to the flexibility of our more diverse generating portfolio, lower gas prices and improved operating performance."

Junk Plant Browns Ferry: Snowballing Back To Pre Pre 2011 Red Finding Attitude?

The "Safety Relief Valve" green finding is grossly not appropriate. It tells me the industry still does not have control of the SRV reliability...

05000259/2016003, 05000260/2016003, 05000296/2016003; 07/01/2016–09/30/2016; Browns Ferry Nuclear Plant, Units 1, 2 and 3; (Equipment Alignment, Fire Protection, Licensed Operator Requalification and Performance, Operability Determinations and Functionality Assessment, Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretion).  

The report covered a three-month period of inspection by resident and regional inspectors.  Six non-cited violations (NCVs) and one licensee-identified Severity Level IV NCV were identified.  The significance of inspection findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP) dated April 29, 2015.  Cross-cutting aspects are determined using IMC 0310, “Components Within the Cross Cutting Areas” dated December 4, 2014.  All violations of NRC requirements are dispositioned in accordance with the NRC’s Enforcement Policy dated August 1, 2016.  The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 6.

Cornerstone:  Initiating Events

• Green.  An NRC identified non-cited violation (NCV) of Renewed License Number DPR-52, condition 2.C.(14) was identified for the licensee’s failure to implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c).  Specifically, the licensee failed to establish a compensatory roving fire watch, within 1 hour of rendering the spray systems that protect the Main 500kV transformer 2B and Unit Service Station Transformer (USST) 2B nonfunctional.  As an immediate corrective action, the licensee established the required fire watch and entered the violation into the licensee's corrective action program as CR 1203990.

The performance deficiency was more-than-minor because it was associated with the protection against external factors (Fire) attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.  This finding was evaluated in accordance with NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013.   The inspectors determined the finding was Green because the finding did not affect the reactor’s ability to reach and maintain the fuel in a safe and stable condition.  The inspectors determined that the finding had a cross-cutting aspect in the Human Performance area of Change Management (H.3) because leaders failed to clearly establish the control room's ownership of Fire Protection Requirements Manual (FPRM) usage as part of the NFPA 805 transition. (Section 1R05)

• Green.  A self-revealing Non-cited Violation (NCV) of Technical Specification (TS) 5.4.1.d, Fire Protection Program Implementation, was identified for the licensee’s failure to maintain the integrity of the high pressure fire protection piping.

The licensee’s immediate corrective action was to isolate the leak and entered this issue into their corrective action program as CR 1102016. This performance deficiency was more than minor because it adversely affected the Initiating Events cornerstone objective of protection against external factors such as fire.  Specifically, the high pressure fire protection system piping was unable to maintain the required pressure during a system demand.  This finding was evaluated in accordance with NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013.   The inspectors determined the finding was Green because the finding did not affect the reactor’s ability to reach and maintain the fuel in a safe and stable condition.  The inspectors assigned a cross cutting aspect of Operating Experience because there was a similar occurrence of a fire protection piping break at Browns Ferry caused by heavy construction vehicle traffic in 2014 (P.5).  (Section 1R15)

Cornerstone:  Mitigating Systems

• Green.  An NRC identified non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings" was identified for the licensee's failure to ensure sufficient clearance was available following a replacement of the Core Spray minimum flow valve actuator motors.  Modifications personnel failed to identify that the resulting clearances were less than permitted by TVA procedure MAI-4.10 “Piping Clearance Instruction” and that they required an engineering evaluation.  As an immediate corrective action, the licensee cut away portions of floor grating to establish an acceptable amount of clearance for the valves.  The violation was entered into the licensee's corrective action program as CRs 1161330 and 1169591.

The performance deficiency was more-than-minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage).  Specifically, the inadequate clearance resulted in an analysis showing that ASME code allowable design stresses would be exceeded under accident conditions.  Exceeding design stresses created a reasonable doubt on the operability and reliability of loop 2 of the Core Spray system for Units 2 and 3.  This finding was evaluated in accordance with NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012.  The inspectors determined the finding was Green because the finding was a deficiency affecting the qualification of the Core Spray loop.  Operability was maintained because an engineering evaluation demonstrated, through the use of alternative analytical methods, that the piping stress criteria in Appendix F of Section III of the ASME Boiler and Pressure Vessel Code was satisfied and that the stresses in the valve would not cause distortions of a magnitude that would prevent operation of the valve.  The inspectors did not assign a crosscutting aspect because the performance deficiency was not reflective of present licensee performance since it occurred more than three years ago.  (Section 1R04)

• Green.  An NRC identified NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action" was identified for the licensee's failure to promptly identify conditions adverse to quality associated with the prompt determination of operability (PDO) for CR 1061051.  As an immediate corrective action, the licensee entered the violation into the licensee's corrective action program as CR 1193943.  

The performance deficiency was more-than-minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage).  Specifically, had the deficiencies in the PDO been identified, engineers would have recognized that the resulting stresses exceeded allowable design stresses in the valve vendor's weak link analysis and approached the yield strength of the stem material.  As a result, the practice was permitted to continue until the valve stem catastrophically failed. This finding was evaluated in accordance with NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012.  The inspectors determined the finding required a detailed risk evaluation because the finding represented a loss of system function and/or function for the high pressure coolant injection (HPCI) system.  Senior Reactor Analyst performed a detailed risk evaluation using the Standardized Plant Analysis Risk (SPAR) model for Browns Ferry Unit 1.   The HPCI system was modeled as unavailable for a conservative exposure period of 7 days.  The delta CDF estimate was less than 1E-6/yr range, which represents a finding of very low safety significance (Green).  The dominant core damage sequence was an inadvertent open relief valve, failure of HPCI, and failure to depressurize.   The availability of additional injection sources helped minimize the risk significance. The inspectors determined that the finding had a cross-cutting aspect in the Design Margins area of the Human Performance aspect (H.6), because engineers did not demonstrate the behavior of carefully guarding margins to ensure that safety related equipment was operated and maintained within design margins.  (Section 4OA2.5)

• Green. A self-revealing NCV of TS 3.5.1, Emergency Core Cooling Systems, Condition E in that an inoperable Automatic Depressurization System (ADS) valve function existed longer than the allowed technical specification time.  The licensee implemented corrective actions by declaring the affected component inoperable per technical specifications, identified preventative maintenance procedures as the cause, repaired the breaker stabs to restore the circuit, and re-performed the surveillance to establish operability.  This issue was entered into the licensee's corrective action program as CR 1161991.

The performance deficiency was more than minor because it adversely affected the Mitigating Systems cornerstone attribute of equipment performance.  Specifically, one of the TS required ADS valves opening capability was not fully qualified.  Using NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012,  the inspectors determined the finding was of very low safety significance (Green) because the finding did not represent a loss of system safety function as the other five Main Steam Relief Valve (MSRV) ADS functions were still available.  The inspectors assigned a cross cutting aspect of Identification since the licensee had not taken sufficient post maintenance actions to verify function of the alternate breaker for the ADS valve 3-PCV-001-0022. (P.1) (Section 4OA3.1)

• Green.  A self-revealing NCV of TS 3.4.3, Safety Relief Valves was identified for two required MSRVs being inoperable longer than the allowed outage time and follow on action completion time.  The licensee’s immediate corrective action was to replace all Unit 3 MSRV pilot valves prior to the completion of the refueling outage.  This issue was entered into the licensee’s corrective action program as CR 1157981. 

The performance deficiency was more than minor because it adversely affected the Mitigating Systems cornerstone attribute of equipment performance.  Specifically, two required MSRVs were not able to lift within their required pressure band.  This performance deficiency was screened using NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012.   This performance deficiency screens to Green because although the system was inoperable for greater than its allowed outage time and follow on action completion time, the system maintained its safety function.  The inspectors assigned a cross cutting aspect of Resolution since the licensee has not taken sufficient corrective actions to address the continued  out of tolerance lift results caused by corrosion bonding of the MSRV pilot valve seats. (P.3) (Section 4OA3.3)   A violation of Severity Level IV that was identified by the licensee has been reviewed by the NRC.  .  Corrective Actions taken or planned by the licensee have been entered in the licensee’s corrective action program.   The violation and corrective action tracking numbers are listed in Section 4OA7 of this report.