More Fleet Wide Ethics Training for Entergy: History Shows It Don't Work

Entergy has had hundreds of falsification and other ethical problems over recent years ending in Confirmatory Orders demanding fleet wide ethical training.  Fleet wide ethical training and scapegoating the little guys has been proven not to work. We need a investigation on is ethics training effective.

NRC Issues Confirmatory Order to Entergy  

The Nuclear Regulatory Commission has issued a Confirmatory Order to Entergy Nuclear Operations, Inc., and Entergy Operations, Inc., documenting actions they have agreed to take to implement programs designed to prevent willful misconduct at their fleet of seven operating nuclear power plants. 

As a result of investigations at the Grand Gulf nuclear power plant in Port Gibson, Miss., Entergy identified that (1) an examination proctor deliberately compromised examinations by providing inappropriate assistance to trainees; (2) workers did not perform required rounds to check equipment and plant conditions; and (3) workers deliberately provided inaccurate documentation indicating they had done so. Three apparent violations of NRC requirements are described in a Nov. 20, 2017, inspection report.  

Entergy requested the Alternative Dispute Resolution process with the NRC to discuss corrective actions. The process uses a neutral mediator with no decision-making authority to assist the NRC and its licensees in coming to an agreement.  Following a meeting on Feb. 6 with Entergy officials, the NRC issued a Confirmatory Order documenting actions the company agreed to take. In addition to Grand Gulf, the Entergy fleet includes Arkansas Nuclear One in Russellville, Ark., Indian Point 2 and 3 in Buchanan, N.Y., Palisades in Covert, Mich., Pilgrim in Plymouth, Mass., River Bend in St. Francisville, La., and Waterford in Killona, La.
 

Junk Plant Pilgrim: Leaking Feedwater Heaters And Another Total Loss Of Offsite Power

That 23 line is interesting. It is piss ass small line and extremely unreliable. But it plays a disproportional role in any violation levels if it stays operational. Of course, if the plant was operational, they would have had another hard trip.

The industry and NRC basically believes a plant at shutdown is more risky than at power. So they might be required to shutdown, the utilities will justify staying at power on it more risky to be shutdown.   

Facility: PILGRIM Region: 1 State: MA Unit: [1] [ ] [ ] RX Type: [1] GE-3 NRC Notified By: MICHAEL HETTWER HQ OPS Officer: DONG HWA PARK	Notification Date: 03/13/2018 Notification Time: 15:54 [ET] Event Date: 03/13/2018 Event Time: 10:00 [EDT] Last Update Date: 03/13/2018
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(3)(v)(B) - POT RHR INOP	Person (Organization): MARC FERDAS (R1DO) JEFFERY GRANT (IRD)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	N	0	Cold Shutdown	0	Cold Shutdown

Event Text

OFF-SITE POWER UNAVAILABLE DUE TO WINTER STORM "On March 13, 2018 at 1000 hours [EDT], with the reactor in Cold Shutdown condition, both 345kV incoming power lines and 23 kV Shutdown Transformer became unavailable during the Northeast winter storm. Per procedures, the emergency on-site emergency power supplies (Emergency Diesel Generators) were running and providing power to essential systems. In addition, the back-up Diesel Air Compressor was in service and one Reactor Protection System bus was on the back-up power supply prior to the loss. "With both 345kV incoming power lines and 23 kV Shutdown Transformer unavailable, Pilgrim Nuclear Power Station procedures direct a report be made to the NRC per the requirements of Title 10 Code of Federal Regulations 50.72(b)(3)(v), any event that could have prevented the fulfillment of the safety function. No actual loss of safety function has occurred since the on-site emergency power supplies are maintaining the reactor in a safe shutdown condition and removing residual heat. "The loss of incoming power is under investigation. "This event had no impact on the health and/or safety of the public. "The NRC Resident Inspector has been notified."

PSEG Starving Funding For Troubled Hope Creek and Salem

PSEG Canceling Nuclear Plant Spending Due to Stalled Bailout 

The state's biggest utility says it's canceling funding for capital projects at a nuclear plant because of a stalled legislative effort to financially rescue the state's nuclear industry.

March 2, 2018, at 2:49 p.m.

PSEG, Exelon cancel capital projects at Salem nuke after legislation stalls

Public Service Enterprise Group and Exelon Corp. have axed multiple capital projects at their jointly-owned Salem nuclear plant after the New Jersey legislature failed to pass a bill to support the state's nuclear generation.

The bill would have supported PSEG's nuclear plants but the legislation was shelved in the Senate. The subsidies would have added about $350 million annually over 10 years, to the plants' revenue

The spending would have included New Jersey gets about 40% of its electricity from nuclear generation, but owners of the state's plants now say they will not make further investments beyond requirements from the Nuclear Regulatory Commission and other regulations. 

The decision means PSEG will stop working to make the plants more efficient and reliable. NJ.com frames it as a "threat" from generation owners of "dirtier air, higher bills," if subsidies are not provided.

In a Form 8-K filed with the U.S. Securities and Exchange Commission, PSEG said that "funding of these projects may be restored when and if legislation is enacted in New Jersey that sufficiently values the attributes of nuclear generation and Salem benefits from such legislation."…

The bill included both efficiency and solar initiatives, along with hundreds of millions in support for nuclear

The Scale Of The Problem in A Million Components System: SRV

If this is how they treat all the components in their plants, they are going to be overrun with problems.

UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, DC  20555-0001

February 26, 2018

NRC INFORMATION NOTICE 2018-02: TESTING AND OPERATIONS-INDUCED DEGRADATION OF 3-STAGE TARGET ROCK SAFETY RELIEF VALVES 

ADDRESSEES
 All holders of an operating license or construction permit for a nuclear power reactor under Title 10 of the Code of Federal Regulations (10 CFR) Part 50, “Domestic Licensing of Production and Utilization Facilities,” except those that have permanently ceased operations and have certified that fuel has been permanently removed from the reactor vessel.

All holders of and applicants for a power reactor early site permit, combined license, standard design certification, or manufacturing license under 10 CFR Part 52, “Licenses, Certifications, and Approvals for Nuclear Power Plants.”  All applicants for a standard design certification, including such applicants after initial issuance of a design certification rule.  

 PURPOSE
 The U.S. Nuclear Regulatory Commission (NRC) is issuing this information notice (IN) to make addressees aware of recent operating experience related to Target Rock Model 0867F 3-stage safety relief valves (SRVs).  Operating experience has shown that limited flow testing of these valves can result in damage to internal valve components.  This damage can be exacerbated when the valves are re-installed in the plant following testing and subjected to normal plant operating conditions, including steam flow-induced vibrations.  The resultant internal damage has affected valve operability at low steam pressure.  It is expected that addressees will review the information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems.  Suggestions contained in this IN are not NRC requirements.  Therefore, no specific action or written response is required.  

DESCRIPTION OF CIRCUMSTANCES
 Pilgrim Nuclear Power Station

On February 8, 2013, and January 27, 2015, severe winter storms caused loss of offsite power (LOOP) events at Pilgrim Nuclear Power Station (Pilgrim).  These LOOP events resulted in complicated reactor trips, with operators using various systems to lower plant pressure.  In each event, operators noted an unexpected plant response from one of the plant’s four main steam SRVs (Target Rock Model 0867F 3-stage valves) while using the valves to reduce pressure.  During the 2013 event, the “A” SRV did not properly open when it was manually actuated at low plant pressure (i.e., below 300 psig).  Similarly, during the 2015 event, the “C” SRV did not properly open when manually actuated at low plant pressure.  In each case, operators were able to control plant pressure by manually cycling the “B” and “D” SRVs.  

IN 2018-02 Page 2 of 8

Subsequent to the plant reaching cold shutdown following the 2015 event, the licensee removed SRVs “A” and “C” from the plant and sent them—along with a third valve which had been removed from the plant in 2013—to an offsite testing facility for limited flow testing.  The valves were replaced with spare Model 0867F SRVs, and the plant restarted on February 8, 2015.  During limited flow testing at the offsite test facility, the valves consistently opened when exposed to steam pressure at the lift setpoint (approximately 1100 psig) but did not fully close.  The valves were disassembled to allow inspection of the main stage internal components.  This inspection revealed: (1) damage to the threaded connection between the valve stem and the main piston caused by axial displacement of the main piston; (2) fretting damage to the walls of the main cylinder caused by impingement of the main piston rings; (3) loss of torque on the lock nut and deformation of its locking tab; and (4) shortening of the free height of the main valve spring.  The damaged threads and axial displacement of the main piston created a gap between the stem and piston shoulders, allowing the piston to wobble and/or rotate within the cylinder.  During operation, plant vibrations caused the rings on the loose piston to fret against and eventually wear grooves in the walls of the main cylinder.  These grooves affected piston movement and valve operation at low plant pressure during the 2013 and 2015 Pilgrim events.  On March 16, 2015, Curtiss Wright, parent company of Target Rock, issued a report in accordance with 10 CFR Part 21, “Reporting of Defects and Noncompliance” (Part 21), indicating that Model 0867F 3-stage SRVs are susceptible to internal damage that is caused by limited flow testing (Agencywide Document and Management System (ADAMS) Accession No. ML15077A422). 

The NRC chartered a special inspection team in February 2015 to evaluate the licensee’s performance in response to the LOOP event on January 27, 2015.  Following the inspection, NRC staff issued a finding of low to moderate (White) significance for the licensee’s failure to take appropriate corrective actions for a significant condition adverse to quality associated with the “A” SRV during the 2013 LOOP.  The licensee’s failure to take corrective action to preclude repetition resulted in the failure of the “C” SRV during the January 27, 2015, LOOP event.  The NRC staff subsequently published a special inspection report on May 27, 2015 (ADAMS Accession No. ML15147A412).  On September 1, 2015, the NRC staff issued the final determination and a notice of violation to Pilgrim (ADAMS Accession No. ML15230A217).  

During an April 2015 refueling outage, Pilgrim replaced all four of their Model 0867F 3-stage SRVs with Model 7567F 2-stage Target Rock SRVs.  Curtiss Wright issued interim 10 CFR Part 21 reports for Model 0867F SRVs on May 1, 2015 (ADAMS Accession No. ML15134A017), and June 30, 2015 (ADAMS Accession No. ML15187A172).  In these reports, the vendor described how valve internals could be damaged by excessive velocities and impact forces resulting from limited flow testing.  In the June 2015 report, Target Rock described the root causes of internal valve damage, along with its plan for redesigning the valve and its testing requirements in order to limit future testing and operations-induced damage.  Target Rock also indicated that three other nuclear plants at two sites had Model 0867F 3-stage SRVs installed.  The two facilities are the Edwin I. Hatch Nuclear Plant (Hatch), Units 1 and 2, with 11 Model 0867F valves installed in each unit, and the James A. Fitzpatrick Nuclear Power Plant (Fitzpatrick), with three Model 0867F valves installed out of a total of 11 SRVs.

Edwin I. Hatch Nuclear Plant, Units 1 and 2

During a February 2016 refueling outage, Hatch, Unit 1, removed its 11 3-stage SRVs for lift setpoint testing required under technical specification surveillance requirement 3.4.3.1 and the licensee’s inservice testing program.  The valves were tested at the NWS Technologies testing facility on March 30, 2016.  All of the valves properly opened during limited flow testing, but three of the 11 valves failed to properly close following their second cycling on the test stand.  

Two of the three valves that failed to properly close were disassembled, at which time inspectors noted severe internal degradation similar to that found in the SRVs removed and tested by Pilgrim.  The licensee for Hatch contracted an independent engineering firm to evaluate any impact of the damage on valve operability.  The engineering analysis concluded that the potential for valve binding in the open direction was low despite the damage noted in the Hatch, Unit 1, SRVs.  The analysis noted that the fretting wear grooves created by the main piston rings in the main guides of the Hatch, Unit 1, valves were not as steep and deep as those in the Pilgrim valves.  Based on the valve condition and analysis, the licensee determined that the Hatch, Unit 1, SRVs would have been able to perform their design function to open and close over their operational range (down to 150 psig) when installed in the plant, and that the SRVs still installed in Hatch, Unit 2, were operable but in a degraded/nonconforming condition due to the potential for in-service vibration wear.  

The NRC dispatched a special inspection team to Hatch on April 4, 2016.  The team reviewed all aspects of the Hatch operating experience, as well as the licensee’s rationale for the actions it took following review of the Pilgrim events and the vendor’s Part 21 reports.  The NRC inspectors identified no significant performance deficiencies.  Hatch Unit 2 performed a six day mid-cycle maintenance shutdown on May 21, 2016, (14 months into their 24-month operating cycle) to replace, test, and inspect the 11 SRVs.  Both Hatch Units 1 and 2 were returned to operation with refurbished 3-stage Target Rock SRVs that had undergone the vendor recommended modified testing and inspection requirements discussed in the June 30, 2015, Part 21 interim report.  This included removing the requirement to perform a final limited flow cycling of the valve upon reassembly and checking installed valves for evidence of de-shouldering by measuring the gap between the stem and main piston shoulders.  The special inspection report was published on June 10, 2016 (ADAMS Accession No. ML16162A631).

James A. Fitzpatrick Nuclear Power Plant

The licensee for Fitzpatrick removed two of its three Model 0867F 3-stage Target Rock SRVs in June and July of 2016.  One of these valves exhibited degradation similar to that seen at Pilgrim and Hatch, although the fretting wear in the main cylinder was not as severe.  The third 3-stage SRV was replaced in January 2017 and did not exhibit any degradation similar to Pilgrim and Hatch. All three 3-stage SRVs were replaced with 2-stage Target Rock SRVs.

Vendor Corrective Actions

In its June 30, 2015, interim Part 21 report, Target Rock recommended that licensees with Model 0867F 3-stage SRVs installed in their plants assess the valves for the potential of fretting-induced damage and inspect valves as needed.  The impacted licensees (Hatch and Fitzpatrick) responded as described above.  The interim Part 21 report also recommended a revised method for performing limited flow testing on Model 0867F 3-stage SRVs intended for installation at a plant.  The revised method involved additional verifications of the integrity of valve internals following limited flow valve cycling.  Valves are to be checked for thread damage, stem to piston shoulder gap, main spring height, and lock nut torque.  Following satisfactory inspection and retorqueing of the valve internals, the valve can be leak checked, then reinstalled in the plant without the need to cycle the valve again via limited flow testing.  Much of the previous valve damage that led to operational challenges was initiated by this final valve cycling  prior to installation, which could cause the main piston and lock nut to lose torque and become loose on the stem.  Valves were being reinstalled in this condition without any further inspection, creating the conditions for fretting-induced damage to the main cylinder wall.

On February 3, 2017, Target Rock issued a final Part 21 report (ADAMS Accession No. ML17039A569) to inform its customers of design changes to the Model 0867F 3-stage  SRV.  Target Rock evaluated the effectiveness of the changes during limited and full-flow  valve testing between August and November of 2016.  Target Rock recommends this new design as a long-term solution to all utilities that currently have installed or plan to install Model 0867F 3-stage SRVs in their plants. 

 BACKGROUND  

 Valve Design and Actuation

Figure 1 of this document shows a Target Rock Model 0867F 3-stage SRV in the closed position.  Additional arrows and labels have been added to show location of the lock nut, lower piston ring, stem shoulder, and gagging device.

Figure 1:  Target Rock Model 0867F 3-Stage SRV

When installed in the plant, the SRV actuates in the pressure relief mode by sensing system pressure at the pilot valve.  When pressure reaches the valve setpoint, the metal sensing bellows expands against the pilot preload spring and opens the pilot valve.  This allows steam from inside the bellows to act on top of the second stage piston.  The steam pressure causes the second stage piston to compress the second stage preload spring, which unseats the second stage disc.  This relieves steam pressure from the top of the main piston through a vent path to the SRV outlet.  When pressure is relieved from the top of the main piston, system pressure acting on the underside of the piston through orifices drilled in the main guide is enough to overcome the closing force of the main valve spring.  The main piston is threaded onto the stem of the main disc.  As the piston pulls the stem upward in its cylinder, the main disc unseats and pops open, thus relieving main steam pressure through the SRV tailpipe (outlet).  During the Pilgrim events, SRVs were being used at lower plant pressures in pressure control mode.  In this mode, operators manually open the valves from a switch in the control room, as needed, to lower plant pressure.  The switch sends a signal to the solenoid, which moves the remote air actuator to unseat the second stage disc, causing the main piston to reposition and open the main disc, as described above.   

 Root Cause and Method of Damage
In its initial and interim Part 21 reports, Target Rock concluded that valve internal degradation is initiated during limited flow testing at offsite testing facilities.  Limited flow testing of the Model 0867F 3-stage SRV exposes the valve internals to excessive velocities and impact forces.  The dynamic loads during testing can far exceed those which the valves experience during an in-plant actuation.  This is mainly due to the presence of the gagging device, which is a plate with a small orifice inserted just downstream of the main disc to block off most of the steam flow (see Figure 1 of this document).  The gag is necessary to ensure sufficient inlet pressure to fully open the valve in testing.  It also minimizes the amount of potentially radioactive steam exhausted from the valve during testing.  However, by blocking the exhaust path through the valve outlet, the gag causes a reaction force with the underside of the main disc as the valve begins to open.  The added force caused by differential pressure across the main piston creates a higher than normal opening force on the main valve assembly.  This extra opening force causes the main piston to reach a higher velocity upon valve actuation, which results in excessive impact force when the main spring becomes fully compressed and arrests valve motion.  The impact force leads to damage to valve internal components, such as that discovered when valves from Pilgrim, Hatch, and Fitzpatrick were disassembled.  

Degradation to valve internals—such as plastic deformation of valve threads, loss of lock nut torque, and de-shouldering of the stem and main piston—allows the piston to wobble and/or rotate inside its cylinder.  When a valve in this condition is reinstalled in the plant, steam flow-induced vibrations can cause the main piston rings to fret against the cylinder liner and form grooves over time.  If these grooves become deep enough, and develop a steep ramp angle, they can impede valve motion when the damaged valve is actuated (see Figures 2 and 3 of this document).  The likelihood of impeding valve motion is greater at low plant pressures, where the differential pressure across the main piston is less.  Fretting can also cause wear on the piston rings themselves, allowing steam to leak, which further impacts valve actuation.  Finally, a shortened main spring can lead to lack of sufficient driving force to reseat (close) the SRV following actuation.  

IN 2018-02 Page 6 of 8





Description of Valve Redesign

In 2016, Target Rock implemented design changes on its Model 0867F 3-stage SRVs that reduce main piston velocity and impact forces during limited flow testing.  The design changes slow the rate at which steam flows into the underside of the main piston upon valve actuation.  This, in turn, lowers the driving force behind the main piston, which slows its velocity during actuation and subsequently reduces impact forces when valve motion is arrested.  The design changes also include a modification to the primary pilot seat in order to ensure that valve actuation times continue to satisfy American Society of Mechanical Engineers Boiler and Pressure Vessel Code requirements.
 DISCUSSION
 In the design of boiling water reactors, main steam SRVs support safety functions of both the pressure relief system and the emergency core cooling system (ECCS).  In the pressure relief system, SRVs lift at their design setpoints to prevent overpressurization of the nuclear system.  This protects the nuclear system process barrier from failure, which could result in the uncontrolled release of fission products.  In the ECCS, certain SRVs will lift upon failure of the high pressure coolant injection system in order to reduce plant pressure and allow the low pressure ECCS to protect the reactor during a small break loss of coolant event.

Target Rock SRVs have been in use in the nuclear industry in the United States for several decades.  The original SRV was a 3-stage model introduced in the early 1970s.  Reliability issues with this model led to the introduction of a 2-stage model in the mid-1970s.  The 2-stage SRVs were susceptible to setpoint drift caused in part by corrosion bonding of the pilot valve seat and disc.  Target Rock reintroduced the 3-stage SRV in 1998, and modified the design again in 2008 with the expectation that users of the valve would convert back to the 3-stage model based on improved setpoint performance.  

Since 2011, there have been anecdotal instances in which Model 0867F valves were inspected during testing and found to have internal damage, such as grooves worn into their main cylinders.  However, the primary cause of operability issues for Model 0867F valves between 2011 and 2015 was pilot valve leakage, which is a well-known and monitored phenomenon. 
Cylinder Wall Cylinder Wall
Main  Piston
Piston Ring Grooves formed by Piston Rings
Figure 2:  Expanded Diagram of Groove Formed by Piston Ring Fretting
Figure 3:  Photo of Grooves Caused by Fretting of Cylinder Wall
IN 2018-02 Page 7 of 8

Increased scrutiny following inoperability of Pilgrim’s “C” SRV during the plant’s complicated scram in 2015 led to the discovery of more severe internal degradation of valve internals.  

Target Rock took action to notify the industry of the operating experience at Pilgrim using the process defined in 10 CFR Part 21.  As they identified the root cause of valve damage and operational failures, Target Rock updated stakeholders with interim reports which recommended improved limited flow testing techniques, and notified industry of the availability of an improved valve design.  
 CONTACT
 This IN requires no specific action or written response.  Please direct any questions about this matter to the technical contact(s) listed below or the appropriate Office of Nuclear Reactor Regulation or Office of New Reactors project manager.


 /RA/ (Paul G. Krohn for)   /RA/
 Timothy J. McGinty, Director   Christopher G. Miller, Director  Division of Construction Inspection  Division of Inspection and Regional Support   and Operational Programs   Office of Nuclear Reactor Regulation Office of New Reactors


Technical Contacts: Eric Thomas, NRR/DIRS  301-415-6772  E-mail: Eric.Thomas@nrc.gov

 John Billerbeck, NRR/DE  301-415-1179  E-mail: John.Billerbeck@nrc.gov

Note:  NRC generic communications may be found on the NRC public Web site, https://www.nrc.gov, under NRC Library.  
IN 2018-02 Page 8 of 8

NRC INFORMATION NOTICE 2018-02, “TESTING AND OPERATIONS-INDUCED DEGRADATION OF 3-STAGE TARGET ROCK SAFETY RELIEF VALVES,” DATED:  February 26, 2018



ADAMS Accession No.: ML18029A741          *concurred via e-mail             CAC/EPID: A11008/L-2017-CRS-0058 OFFICE Tech Editor  NRR/DIRS/IOEB NRO/DEI/MEB NRR/DE/EMIB/BC NRR/DIRS/IOEB/BC NAME JDoughtery EThomas TScarbrough SBailey RElliott DATE 11/13/2017 11/30/2017 01/16/2018 02/01/2018 02/01/2018 OFFICE NRR/DIRS/IRGB/LA NRR/DIRS/IRGB/PM NRR/DIRS/IRGB/BC NRO/DCIP/D NRR/DIRS/D NAME ELee TGovan HChernoff (w/comment) TMcGinty (PKrohn for) CMiller DATE 02/06/2018 02/06/2018 02/20/2018 02/22/2018 02/26/2018

Junk Plant Grand Gulf's Annual Performance Assessment

Really, these guys are in the second highest performance classification and are declining fast... Indications of problems with the ROP?

 The U.S. Nuclear Regulatory Commission (NRC) has completed its end-of-cycle performance assessment of Grand Gulf Nuclear Station, reviewing performance indicators (PIs), inspection results, and enforcement actions from January 1, 2017, through December 31, 2017.  This letter informs you of the NRC’s assessment of your facility during this period and its plans for future inspections at your facility.  The NRC concluded that overall performance at your facility preserved public health and safety.

The NRC determined the performance at Grand Gulf Nuclear Station during the most recent quarter was within the Regulatory Response Column, the second highest performance column of the NRC’s Reactor Oversight Process (ROP) Action Matrix.  This conclusion was based on a parallel PI inspection finding having low-to-moderate safety significance (i.e., White) in the Initiating Events Cornerstone, which was effective as of the first quarter of 2017.  This finding was discussed in NRC Inspection Report 05000416/2017013 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17342B130), dated December 6, 2017, in which the NRC concluded that the station’s actions in response to a White Unplanned Scrams per 7000 Critical Hours PI, which you reported for the third and fourth quarters of 2016, did not meet the objectives of Inspection Procedure 95001, “Supplemental Inspection Response to Action Matrix Column 2 Inputs.”  

Therefore, in addition to ROP baseline inspections, the NRC plans to conduct an additional supplemental inspection in accordance with Inspection Procedure 95001 to review your station’s actions to address the weaknesses described in the above inspection report as they relate to the inspection objectives.  The objectives of this inspection are: 1) To assure that the root causes and contributing causes of significant performance issues are understood, 2) To independently assess and assure that the extent of condition and extent of cause of significant performance issues are identified, 3) To assure that corrective actions taken to address and preclude repetition of significant performance issues are prompt and effective, and 4) To assure that corrective plans direct prompt actions to effectively address and

Florida School Shooting

There has been tremendous individual and public financial cost associated with these events. Mostly the tax payers pick up the cost. We should total up the cost and make the manufactures pick up the cost. We should tax the manufactures according to the damage their products make on us.

Last Dying Breath With The TVA behemoth Nuclear Facility

Usually they only replace a small proportion of the equipment. It is only focused on stuff associated with power producting equipment. 

Last Dying Breath With The TVA behemoth Nuclear Facility

http://www.timesfreepress.com/news/breakingnews/story/2018/feb/20/tva-boosts-power-output/464144/

TVA boosts power output at Browns Ferry nuclear plant with $475 million upgrade

It may have been a 3-day holiday weekend for most federal employees, but workers and contractors at TVA's oldest nuclear plant were busy over the weekend working on the first phase of what will one of the largest power upgrades of an existing U.S. nuclear plant.

TVA is installing new equipment on the Unit 3 reactor on its Browns Ferry Nuclear Plant in Alabama as part of its refueling outage following a record 653-day run of power generation at the plant. The scheduled refueling and maintenance outage began early Saturdaymorning and will help TVA to boost the power output at the reactor by more than 14 percent, adding 155 megawatts of power once the refueling and equipment upgrades are completed.

TVA spokesman Jim Hopson said that in addition to the traditional outage work of loading 344 new fuel assemblies, a final round of modifications will be installed that will prepare Unit 3 to become the first of the three Browns Ferry units to operate at the Extended Power Uprate approved last year by the U.S. Nuclear Regulatory Commission. New equipment is being added on both the nuclear and non-nuclear parts of Browns Ferry to generate more steam and to use that steam to produce more power.

Over the next year, TVA plans similar power upgrades on the other two reactors at Browns Ferry. In total, TVA is spending $475 million to add an additional 465 megawatts of electricity at the 3-unit plant, or enough to power an additional 280,000 homes.

"Outages are always important because it's our opportunity to do the work necessary to safely and reliably generate electricity for the next two years," said Lang Hughes, Browns Ferry site vice president. "There is added importance to this and our next two outages because we will complete the remaining work needed to operate each unit at extended power uprate conditions to serve the energy needs of the Tennessee Valley."…

NRC Stratiegic Plan: Government Hating And Deregulation

Risk Informed regulations isn't science based anything. It is fundimentally based on self interested assumptions with highly technical people.

Remember, we are in the largest economic crisis the nukes ever seen...

 NRC Presents FY 2018-2022 Strategic Plan

SAFETY STRATEGIES Safety Strategy 1: Maintain and enhance the NRC’s regulatory programs, using information gained from domestic and international operating experience, lessons learned, and advances in science and technology.

Safety Strategy 2: Further risk-inform the current regulatory framework in response to advances in science and technology, policy decisions, and other factors, including prioritizing efforts to focus on the most  safety-significant issues.

Safety Strategy 3: Enhance the effectiveness and efficiency of licensing and certification activities to maintain both quality and timeliness of licensing and certification reviews.

Safety Strategy 4: Maintain effective and consistent oversight of licensee performance with a focus on the most safety-significant issues.

Safety Strategy 5: Maintain material safety through the National Materials Program in partnership with Agreement States.

Safety Strategy 6: Identify, assess, and resolve safety issues.

Safety Strategy 7: Ensure the NRC maintains its readiness to respond to incidents and emergencies involving NRC-licensed facilities and radioactive materials and other events of domestic and international interest.

Safety Strategy 8: Verify that nuclear facilities are constructed and operated in accordance with permits and licenses and that the environmental and safety regulatory infrastructure is adequate to support the issuance of new licenses.

Junk Plants Palo Verde: Has Their Power History Been So Erratic Lately?

update

Power Reactor	Event Number: 53215
Facility: PALO VERDE Region: 4 State: AZ Unit: [1] [ ] [ ] RX Type: [1] CE,[2] CE,[3] CE NRC Notified By: JORGE LESTER HQ OPS Officer: JEFF HERRERA	Notification Date: 02/16/2018 Notification Time: 02:50 [ET] Event Date: 02/15/2018 Event Time: 21:53 [MST] Last Update Date: 02/16/2018
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL 50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE	Person (Organization): GREG WERNER (R4DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	A/R	Y	100	Power Operation	0	Hot Standby

Event Text

AUTOMATIC REACTOR TRIP DUE TO LOW DEPARTURE FROM NUCLEATE BOILING SIGNAL "The following event description is based on information currently available. If through subsequent reviews of this event additional information is identified that is pertinent to this event or alters the information being provided at this time a follow-up notification will be made via the ENS or under the reporting requirements of 10CFR50.73. "On February 15, 2018, at approximately 2153 Mountain Standard Time (MST), the Palo Verde Generating Station (PVGS) Unit 1 Control Room received Reactor Protection System alarms for Low Departure from Nucleate Boiling Ratio and an automatic reactor trip occurred. Prior to the reactor trip, Unit 1 was operating normally at 100 percent power. Plant operators entered the emergency operations procedures and diagnosed an uncomplicated reactor trip but noted that Reactor Coolant Pumps 1B and 2B were not running due to a loss of power. All CEAs [Control Element Assemblies] fully inserted into the core. Following the reactor trip, all nuclear instruments responded normally. No emergency classification was required per the PVGS Emergency Plan. "The PVGS Unit 1 safety related electrical busses remained energized from normal offsite power during the event. The Unit 1 'B' Diesel Generator is currently removed from service for maintenance. Due to ongoing planned maintenance on NAN-X02, Startup Transformer 2, fast bus transfer for NAN-S02 (from NAN-S04) was blocked. This resulted in a loss of offsite power to NAN-S02 and NBN-S02. The offsite power grid is stable. Unit 1 is currently stable in Mode 3 with the reactor coolant system at normal operating temperature and pressure. "The event did not result in any challenges to fission product barriers and there were no adverse safety consequences as a result of this event. The event did not adversely affect the safe operation of the plant or the health and safety of the public. "The NRC Resident Inspector has been informed of the Unit 1 reactor trip." * * * UPDATE ON 2/16/18 AT 1640 EST FROM DAVID HECKMAN TO DONG PARK * * * "Unit 1 is stable in Mode 3 following an uncomplicated trip. Offsite power has been restored to non-safety related electrical busses. Troubleshooting continues to determine the cause of the event. "During performance of the alarm response procedure, it was identified that the seismic monitoring (SM) system had been in alarm since the reactor trip and was incapable of performing its emergency plan function. Pursuant to 10 CFR 50.72(b)(3)(xiii), this condition constitutes a major loss of emergency assessment capability. Compensatory measures have been implemented in accordance with PVNGS procedures to provide alternative methods for HU2.1 event classification with the SM system out of service. Maintenance is currently in progress to restore SM system functionality." The licensee notified the NRC Resident Inspector. Notified R4DO (Werner).

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LaSalle Torus Discovery Is A Example The NRC Doesn't Inforce Regulations

This is my example we don't know the true condition per licensing of every plant in the nation. We are going to have a lot of surprises in the next big accident... And the gap between licensing and the actual conditions of the plant are widening. Can you imagine all the processes though the decades that was missed by the licensee and NRC. It is horrible...  

LaSalle Inspection Report 

It is imperative a licensee knows the conditions of the safety equipment and all documentation reflects the actual conditions. The torus has probably been inop since the plant has been in operation. This isn't the case.

When found, the torus should have been declared inop and emediately shutdown till the paperwork has been fixed. Plus an additional amount of time. It would help keep everyone else keep safe fearing the NRC would thrown down the hammer on them.

(Closed) Unresolved Item 05000373; 05000374/2016001–01:  Adequacy of Changes to Pool Swell Analysis a. Inspection Scope During the 2016 first quarter integrated inspection period, the inspectors reviewed the operability evaluation associated with loss of coolant accident suppression pool analysis.  The inspectors identified an unresolved item involving changes to the methodology and design assumptions of the suppression pool analysis and whether those aforementioned changes provide a reasonable expectation that the affected systems, structures and components were operable. During the follow-up inspection activities to the Unresolved Item (URI), the inspectors reviewed LaSalle County Station, Units 1 and 2—Issuance of Amendments Re:  Request to Revise Suppression Pool Swell Design Analysis and the Facility Licensing Basis (CAC NOS. MF8702 AND MF8703); dated October 30, 2017.  The inspectors also reviewed Operability Evaluation OE 12–003; Potential to Increase Pool Swell Loads; Revision 5 and supporting calculations of record.  The inspectors determined the licensee’s operability evaluation provided a reasonable expectation of operability.  Based on this review, the inspectors sufficiently resolved these concerns and consider URI 05000373; 05000374/2016001–01 closed with no performance deficiencies identified; however, during this review, the inspectors identified one additional issue described below. This operability inspection constituted one sample as defined in IP 71111.15–05. b. Findings Primary Containment Structure, Suppression Pool Columns, Downcomer Vent and Downcomer Vent Bracing Did Not Meet Seismic Category I Requirements Introduction.  A finding of very low safety significance (Green) and an associated NCV  of 10 CFR Part 50, Appendix B, Criterion III, “Design Control,” was identified by the inspectors for the failure to ensure the adequacy of the design for the primary containment structure, suppression pool columns, downcomer vents and downcomer vent bracing.  Specifically, the inspectors identified three representative examples where the licensee failed to perform adequate design calculations resulting in the design not being in conformance with Seismic Category I requirements as defined in UFSAR Sections 3.8.1.4.1, 3.8.1.5 and 3.8.6. Description.  UFSAR Table 3.2–1 delineated the primary containment structure and downcomer vent as Seismic Category I and meeting the quality assurance requirements of 10 CFR Part 50 Appendix B.  The suppression pool columns were part of the primary containment structure and support the drywell floor.  The columns were designed to transfer design loading from the drywell floor to basemat.

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In UFSAR Section 3.8.1.1.1.1 described the primary containment as utilizing a Mark II over/under pressure-suppression configuration.  The primary containment consisted of a steel pressure vessel enclosed by a concrete shield wall both supported by a concrete basemat.  The primary containment was enclosed by the reactor building, a reinforced-concrete structure functioning as a secondary containment. The drywell was connected to the suppression chamber by downcomer pipes.  Steam that could be released in the drywell during a postulated loss-of-coolant accident was channeled through these downcomer pipes into the suppression pool where it is condensed thus effecting pressure-suppression.  This would result in a lower pressure and temperature. The downcomer vent pipes were braced at Elevation 697’-1” and Elevation 721’-0”.  The downcomer vent bracing design function was to provide horizontal restraint for applied lateral loading on downcomer vent pipes due to the seismic and loss-of-coolant accident design event.  The downcomer vent and downcomer vent bracing design requirements are delineated in Section 5.3.3.4 of LaSalle County Station, "Mark II-Design Assessment Report (LSCS-DAR)," Commonwealth Edison Company, Chicago, Illinois,  September, 1982.  The design assessment report was incorporated by reference in UFSAR Section 3.8.6. During a review of calculations for the primary containment structure, suppression pool columns, downcomer vents and downcomer vent bracing, the inspectors identified the following three representative examples in which the licensee failed to meet the design requirements: • Calculation No. 195B; Containment Assessment; Revision 0; and Calculation  No. 161I; Suppression Pool Columns; Revision 0.  UFSAR Section 3.8.1.4.1 stated, in part, “The design and analysis procedure is in full compliance with the requirements of Article CC–3000 of the ASME B&PV Code, Section III, Division 2…” The design yield strength of reinforcement shall not exceed 60,000 psi as described in Section CC–3422 of Article CC–3000.  In addition, UFSAR Section 3.8.1.5 defined the allowable of Fy as the minimum guaranteed reinforcing steel yield strength.  The licensee used certified material test reports or actual material yield strength for the reinforcing steel in the evaluation of the containment structure and suppression pool columns.  The use of actual material yield strength did not meet American Society of Mechanical Engineers (ASME) Boiler & Pressure Vessel (B&PV) Code Section III, Division 2 and UFSAR requirements.  The licensee documented these deficiencies in Issue Report No. 4070065; NRC Id:  Clarification on Material Strength Values in Calcs; dated October 16, 2017. • Calculation No. L–002547; Assessment of Containment Wall, Basemat, Liner, Reactor Pedestal, Downcomer Bracing, Drywell Floor, and Suppression Pool Columns for 105 percent Power Uprate; Revision 0.  As delineated in Section 5.3.3.4 of LaSalle County Station, "Mark II-Design Assessment Report, the stresses within the downcomer were considered acceptable if they satisfy the ASME B&PV Code, Section III, Subsection NE.  As permitted by Subsection NE–1120 for Metallic Containment components the downcomers were analyzed using Subsection  NB–3650 of Section III.  The licensee did not use the ASME code acceptance limits.  The licensee documented these deficiencies in Issue Report No. 4074674; NRC Id:  Clarification of Design Basis Code of Downcomer Vent; dated November 14, 2017.

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• Calculation No. L–002547; Assessment of Containment Wall, Basemat, Liner, Reactor Pedestal, Downcomer Bracing, Drywell Floor, and Suppression Pool Columns for 105 percent Power Uprate; Revision 0.  Section 5.3.3.4 of LaSalle County Station Mark II-Design Assessment Report described the allowable acceptance limits are based on the 1.6 times the American Institute of Steel Construction (AISC) allowables but no greater than 0.95 times Fy (minimum specified yield strength of section).  The licensee increased the allowable stresses  by 50 percent based on using plastic section modulus properties which exceeded the elastic acceptance limits set forth in Section 5.3.3.4 of LaSalle County Station  Mark II-Design Assessment Report.  The use of plastic section modulus properties would allow for permanent deformation of the material.  Also, the downcomer bracing gusset plate uses plastic section modulus properties as well.  Lastly, the licensee used a dynamic increase factor of 10 percent to increase the allowable acceptance limits.  The dynamic increase factor was not contained in Section 5.3.3.4 of LaSalle County Station Mark II-Design Assessment Report.  The licensee documented these deficiencies in Issue Report No. 4070067; NRC Id:  Clarification on Acceptance Criteria in Calcs; dated October 16, 2017. The inspectors reviewed the operability evaluation in accordance with IMC 0326; Operability Determinations & Functionality Assessments for Conditions Adverse to Quality or Safety; dated November 20, 2017 to assess whether the nonconforming primary containment structure, suppression pool columns, downcomer vents and downcomer vent bracing were operable.  The inspectors identified no performance deficiencies with the operability evaluation.  In response to the inspector’s concern, the licensee initiated CAP documents as AR 4070067; NRC Id:  Clarification on Acceptance Criteria in Calcs; dated October 16, 2017, AR 4070065; NRC Id:  Clarification on Material Strength Values in Calcs; dated October 16, 2017 and AR 4074674; NRC Id:  Clarification of Design Basis Code of Downcomer Vent; dated November 14, 2017. Analysis.  The inspectors determined the licensee’s failure to perform adequate evaluations to demonstrate Seismic Category I compliance for the primary containment structure, suppression pool columns, downcomer vents and downcomer vent bracing was contrary to the design control measures per 10 CFR Part 50, Appendix B, requirements and was a performance deficiency.   The performance deficiency was determined to be more than minor because the performance deficiency was associated with the Barrier Integrity Cornerstone attribute of design control and adversely affected the Cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events.  Specifically, compliance with Seismic Category I design basis requirements was to ensure the primary containment structure, suppression pool columns, downcomer vents and downcomer vent bracing would function as required during a Seismic Category I design basis event and not adversely affect the function of the containment barrier.