Cooper Junk SRVs: 63% Failed Technical Specification Safety Testing

***Update 1/19

Spoke to Cooper's "new" senior resident inspector and the seasoned resident on the phone this afternoon for about 20 minutes. I swear the women are taking over the world(good). She said she is evaluating the LER update as we speak...LER 2015-001-01. Basically the below was my talking points. I gave her this blog's address.... 

I asked how close Cooper is to their MAPI...the SRV piping stresses when outside Tech Specs.

Looking forward to the new inspection report.

***updated 1/17

"Or the fix could be as simple as cycling each SRV open and close once every month to disrupt the oxidize bonding"

The NRC are supposed to be sticklers for details and telling the truth...

Right, Hope Creek this testing period had a 71% failure rate and Cooper has a 63% failure rate...kind of in the ball park, you think each? 

The drastic increase in failures compared to the last four outages should should raise the hairs on the back of your head. Any ethical engineering report like this should openly question this drastic increase and vow to immediately fix it. Why didn't they mention this in the report...what else is Cooper habitually not confronting and fixing at the plant? How come in Mrs Bower's letter to me on Hope Creeks SRV problems he didn't discuss the increase in setpoint accuracy problems? I just saying he is not discussing the painful truth... It is like he is a advertising executive and not a federal regulator. How many SRVs would have failed testing if the limits were +/- 1% or didn't have a stellite coating the on seat and valve? The +/- 3% and Stellite coating is accommodating these defectively designed valves. It is just giving a illusion they fix the problem.  It is destructive "Normalization of Deviance" on steroids. It is a common organizational mental illness.  

On the second SRV going INOP Cooper needs to be shutdown in 24 hours. 

You get it, a ethical organization(s) would never preform an experiment on nuclear power plant safety equipment. They would put the stellite coated internals and valve on a test stand and exactly model the environment and length of duty as in the nuclear plant. They would put the valve in a much more harsh environment than the plant, so the problems would be exaggerated. Then they would test the valves just like they do when it comes out of the nuclear plant. They'd never put that stellite into a nuclear plant without being 1000% sure how the stellite would perform. It would fix the lift setpoint accuracy problems. I am telling you something stinks rotten here.      

LER 2015-001-01: 5 failed TS safety testing 

LER 2011-005-00: 1 failed TS safety testing  

LER 2010-001-00: 2 failed TS safety testing 

LER 2008-002-00: 1 failed TS safety testing  

LER 2008-002-00: 1 failed TS safety testing

Licensee Event Report No. 2015-001-01

***Read what this below sentence in the LER. This is Coopers title of the document. The NRC wants me to make believe these below 16 words don't matter.  Ask Cooper what they are required to do in this case if they find this specific "condition prohibited by technical specification while at power". They are required to emediately shutdown. This is all "Catch 22" crazy circular logic. Right, "a loss of safety function.

Right, it like your brake peddle goes almost down to the floor. It wasn't like that a day ago. Once you put your foot on the peddle it emediately began braking is what it was a day ago. You test your braking power by slamming on the brakes. The car quickly stops like it should. Come on, but are you safe by ignoring this new problem. Normal people's alarm horns would loudly be going on their heads. They would quickly take the car to a mechanic and drive much more slowly while getting it to them.      

Valve Test Failures Result in a Condition Prohibited by Technical Specifications and a Loss of Safety Function

PLANT STATUS

Cooper Nuclear Station (CNS) was in Mode 1, Power Operation, at 100 percent power, when the event was discovered; i.e., January 26, 2015.

BACKGROUND

The pressure relief system includes three American Society of Mechanical Engineers code safety valves (SV) [EllS: SB] and eight safety relief valves (SRV) [EllS: RV], all of which are located on the main steam lines [EIlS: SB] within the drywell [EllS: NH], between the reactor vessel [EllS: RPV] and the first main steam isolation valve [EllS: ISV]. The SVs provide protection against over pressurization of the nuclear system and discharge directly into the interior space of the drywell. The SRVs discharge to the suppression pool and provide three main functions: overpressure relief operation to limit the pressure rise and prevent safety valve opening, overpressure safety operation to prevent nuclear system over pressurization, and depressurization operation (opened automatically or manually) as part of the emergency core cooling system [EllS: B J, BM, BO].

Technical Specification (TS) Limiting Condition for Operation 3.4.3 requires the safety function of seven SRVs and three SVs to be operable. The nominal set pressure and tolerances for these valves are established in CNS TS Surveillance Requirements (SR) 3.4.3.1.

The SRVs installed at CNS are Target Rock Model 7567F, two-stage, pilot-actuated valves with pilot assemblies comprised of Stellite 21 pilot discs and Stellite 6B pilot body seats. The pilot assemblies had been in continuous service since installation in Refueling Outage (RE) 27.

Corrosion bonding occurs when the protective oxide layers of the seat and disc break down and allow a crevice corrosion process to develop between the seat and disc. The seat is machined and then lapped with the disc to create a tight fit with one another. During the material removal process (machining) on both the seat and disc, the protective oxide layer that provides corrosion protection is removed. Because the SRV pilot valves are then assembled, the oxide layer is not given sufficient time to reestablish itself naturally, and no external process, such as pickling, is done to ensure that the oxide layer is reestablished to its full extent without any breaks or discontinuities. When the SRV pilot valves are assembled, the seat and disc are jammed together and air cannot reach the surfaces, therefore the full benefits of the oxide layer of the anti-corrosion material is diminished.

EVENT DESCRIPTION

On January 26 and February 11, 2015, three complete SRVs and five SRV pilot assemblies, removed during RE28 in the Fall of 2014, were as-found tested at National Technical Systems Laboratories, formerly Wyle Laboratories.

The pressure setpoint for SRV pilot assembly serial number 385 is 1090 psig. The TS SR 3.4.3.1 as-found limit of acceptance is 1090 +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1124 psig, 3.119% above the pressure setpoint. For informational purposes, the technicians performed a second and third lift. The results were 1087 psig and 1087 psig, both within 3% of the pressure setpoint.

The pressure setpoint for SRV pilot assembly serial number 386 is 1100 psig. The TS SR 3.4.3.1 as-found limit of acceptance is 1100 +/- 3%. The first actual lift pressure of SRV number 386 was 1192 psig, 8.36% above the pressure setpoint. A second and third lift was performed and the results were 1108 psig and 1112 psig, both within 3% of the pressure setpoint.

The pressure setpoint for SRV pilot assembly serial number 1242 is 1090 psig. The TS SR 3.4.3.1 as found limit of acceptance is 1090 +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1267.7 psig, 16.24% above the pressure setpoint. The results of a second and third lift were 1091 psig and 1090 psig, both meeting the pressure setpoint.

After this failure, testing was halted in order to verify testing accuracy. Testing was found to be the same as used in years past, and testing resumed on February 10 and February 11 for the remaining five SRVs.

The TS SR 3.4.3.1 as-found limit of acceptance for SRV pilot assembly serial number 1243 is 1100 psig +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1139 psig, 3.545% above the pressure point. For informational purposes, a second and third lift was performed. The results were 1112psig and 1105 psig, both meeting the pressure setpoint.

SRV pilot assembly serial number 1241 was tested. The TS SR 3.4.3.1 as-found limit of acceptance is 1090 psig +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1138 psig, 4.404% above the pressure point. A second and third lift was performed. The results were 1106 and 1092 psig, both meeting the pressure setpoint.

BASIS FOR REPORT

CNS is reporting this event as an operation or condition prohibited by plant TS per 10 CFR

50.73(a)(2)(i)(B), and also as a condition that could have prevented the fulfillment of the safety function of structures or systems as defined under 10 CFR 50.73(a)(2)(v).

An existing engineering analysis demonstrated that the reactor vessel would not be challenged during an overpressure event. In addition, a new analysis determined that the existing Minimum Critical Power Ratio (MCPR) operating limit would have protected the MCPR safety limit in the event of an anticipated operational occurrence. As such, this event will not be counted as a Safety System Functional Failure for the Nuclear Regulatory Commission performance indicator since no loss of safety function occurred.

SAFETY SIGNIFICANCE

Although the TS related to the set point lift pressures of the SRV pilot valve assemblies were exceeded, an analysis of this event indicates that the design basis pressures to ensure safety of the reactor vessel and its pressure related appurtenances would not be challenged. Public safety was not at risk. Safety to plant personnel and plant equipment were not at risk.

CAUSE

The direct cause of five of eight SRV pilot valves failing their lift tests is corrosion bonding.

CORRECTIVE ACTIONS

The following corrective actions have been entered into CNS' corrective action program:

1. CNS shall inspect the SRVs during disassembly to ensure there are no indications of binding, vibration, or other mechanical problems that might cause effects similar to that of corrosion bonding.

2. Laboratory work, under the direction of CNS, shall be undertaken to confirm or deny corrosion bonding of the disc and seats as needed. A comparison with previous laboratory findings about SRV pilot valves will be performed to determine, if possible, the role time in-service played in the failures.

3. Based on the results of the inspection and laboratory work, specific findings and corrective action recommendations in the form of a revised root cause investigation report will be completed.

4. If no evidence to refute corrosion bonding is identified, ensure after machining and lapping processes have been completed, that the oxide, passive layer on the seat and disc are fully restored by pickling or an equivalent process.

5. Presuming that no technical reason is discovered to prevent the following, submit to the Nuclear Regulatory Commission a Technical Specification change that requests setpoint changes as noted in EE 10-053; NEDC-33 543P, Revision 0, Class Ill, DRF 0000-0103-4647, dated February 2010; GE-H NEDC-3362OP, Revision 0, May 2011; and GE-H, report 002N5242-R0, entitled, Cooper Cycle 28 SRV Set Point Study.

PREVIOUS EVENTS

Licensee Event Report (LER) 2011-005-00 - On June 22, 2011, one of eight Target Rock SRV pilot valve assemblies failed to lift within TS lift setpoint requirements. Wyle Laboratories performed this testing. The pressure setpoint of the failed pilot assembly was 1090 +/- 32.7 psig; it lifted at 1199 psig. Two subsequent informational lifts were performed for the SRV pilot assembly and were within the TS pressure setpoint tolerances. The mechanistic cause was the same as reported in previous LERs, pilot disc-to-seat corrosion bonding.

LER 2010-001-00 - On January 12, 2010, two of eight Target Rock SRV pilot valve assemblies failed to lift within TS lift setpoint requirements. Wyle Laboratories performed this testing. The pressure setpoint for the first pilot assembly is 1100 +1- 33.0 psig; the SRV pilot assembly lifted at 1166 psig. The pressure setpoint for the second pilot assembly is 1090 +1- 32.7 psig; it lifted at 1139 psig. Two subsequent informational lifts were performed for both SRV pilot assemblies and were within the TS pressure setpoint tolerances. The mechanistic cause was the same as reported in previous LERs, pilot disc-to-seat corrosion bounding.

LER 2008-002-00 - On July 7 through July 9, 2008, the results of Target Rock SRV test data performed at Wyle Laboratories identified that one of eight SRV pilot assemblies failed as-found pressure setpoint testing. The SRV pilot assembly lifted at 1165 psig, outside its TS setpoint tolerance of 1100 +/- 33.0 psig. The mechanistic cause was pilot disc-to-seat corrosion bounding between the Stellite 21 pilot disc and Stellite 6B pilot body seat to cause the SRV pilot assembly to lift outside its TS setpoint tolerance.

LER 2007-002-00 - On February 28 through March 2, 2007, the results of Target Rock SRV tests performed at Wyle Laboratories identified that one of eight SRV pilot valve assemblies failed to lift within its TS lift setpoint of 1090 +/- 32.7 psig. The failure was a result of sufficient corrosion bonding between the SRV pilot valve assembly Stellite 21 disc and the pilot valve Stellite 6B body seat to cause the SRV pilot valve to lift outside its TS setpoint tolerance.

NRC: Indian Point Is Obstinate With Safety Pipe leaks

So I believe outsiders and I have caused this audit. I am particularly irked with the recent fire water leak in Unit 1 wasn't made into LER. The NRC told me in Indian Point's fire water and service water re-licensing responses to them, it felt like Entergy was just babbling to them. They were giving the agency incomplete answers to the NRC questions. So the NRC was irked at Indian Point.

Ultimately what is wrong here, Indian Point put in improper and cheap fire water and service water pipe metal. They are accommodating this safety deficiency by replacing piping sections as leaks develop. They think it is the cheapest fix. They should have took a prolong shutdown decades ago to completely replace all fire water and service water piping with modern corrosion resistance piping. The piping leaks have gotten out of control. The accommodating strategy has taken resources away from other areas. This accommodation eats up employees and resources...it ultimately weakens the organization and the bureacrocy. They got runaway piping leaks at the plant plus bureaucracy problems. The best solution for the health of the bureaucracy, is you cut off the destructive complexity by replacing the piping. Are they systemically accommodating across many other areas? Then you got very few new problems with proper new pipes and little headaches with a regulator trying to jack up your complexity by pushing you into more employees, inspections and complexity caused by a improper accommodation strategy. You get what I talking about, the improper accommodation strategy slowly blinds a bureacrocy with excessive complexity. You just are juggling too many balls in the air. You are effectively stealing money from the future to support the past and the now.                 

"The corrective actions were to weld repair the affected piping followed by replacing piping with very corrosion resistant material(AL6XN)."

They had to shutdown units two's fire water for two hours. They discovered the beginning or the leak in 2008 and it got lost in their terrible work document system until a huge pipe blew out. At one point, they brought a crew into the plant to replace the weaken section of pipe with the small pin hole leak in it. They botched the replacement job, they neglected (screw-up) to replace the leaking section of pipe...it was scheduled to be replace and they replaced the wrong section of expensive pipe. 

NRC INTEGRATED INSPECTION REPORT 05000247/2015001 AND 05000286/2015001
(pg 27)The inspectors reviewed corrective action documents and WOs for identified degradation of the fire protection piping and conducted a walkdown to assess the material condition. In 2010, Entergy generated CR-IP2-2010-5187 due to the discovery of a through-wall leak in the fire protection piping downstream of valve FP-2. This leak was discovered during a UT conducted as extent of condition for a nearby through-wall leak documented in 2008 (CR-IP2-2008-0044). Entergy created WO 135106 to replace the corroded and corroding piping section. In November 2012, the WO was in a ready status and scheduled to be worked. Due to problems obtaining effective isolation for protective tagging due to valve leak-by, the repair was postponed and the work was not done. Entergy had planned a major maintenance outage for the fire protection system for May 2014 to repair leaking valves and sections of corroded piping. Despite being within the isolation boundary and ready to work, the section of piping containing the 2010 leak was not included in the scope of this work. WO 135106 was instead scheduled following Unit 3 3R18 RFO. The inspectors noted that Entergy did not consider the remaining service life of the degraded piping section when delaying the repair from 2012 to 2015. This issue was entered into Entergy’s CAP as CR-IP2-2014-6668.

That is the trouble with organizational bureaucrats...NRC and Entergy...they think the system is safe just if the paperwork is filled out and complete. The get a grade of "A+" for finding the leak, getting it in the document system and getting resources into the plant to replace the pipe...they got a "E -" for improperly executing the plant in excellence. The leak just got completely lost in the bureaucracy and their work document system. Basically the system is riddled with destructive and massive levels of priorities with too little resources. It is a too complex system with not enough funding. If they don't have enough money to properly run the facility, they just jack up the rules and procedure to compensate for what they don't have. Stick it in the beast slowly digesting facts and we won't have to spend money on the piping leaks for many years.        

We only get a terrible skimpy NRC inspection over this. We are overly dependent on the NRC disclosing these problema. What do they got, three or four NRC inspectors on the site. They got somewhat like a 1000 Entergy employees on the site. Who is likely to catch the problem first?  

December 21, 2015

Vice President, Operations

Entergy Nuclear Operations, Inc.

Indian Point Energy Center

450 Broadway, GSB

P.O. Box 249

Buchanan, NY 10511-0249

SUBJECT: PLAN FOR THE REGULATORY AUDIT OF THE SERVICE WATER INTEGRITY AND FIRE WATER SYSTEM AGING MANAGEMENT PROGRAMS PERTAINING TO THE INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION (CAC NOS. MD5407 AND MD5408)

Dear Sir or Madam:

By letter dated April 23, 2007, as supplemented by letters dated May 3, 2007, and June 21, 2007, Entergy Nuclear Operations, Inc. (Entergy), submitted an application pursuant to Title 10 of the Code of Federal Regulations Part 54, to the U.S. Nuclear Regulatory Commission

(NRC) for renewal of the operating licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3). The NRC staff documented its findings in the Safety Evaluation Report (SER) related to the license renewal of IP2 and IP3, which was issued August 11, 2009 and supplemented August 30, 2011 (SER Supplement 1), and November 6, 2014 (SER Supplement 2). Subsequent the issuance of SER Supplement 1, the NRC staff identified additional operating experience at several nuclear power plants regarding recurring internal corrosion, corrosion occurring under insulation, and managing aging effects for fire water system components. To address this operating experience, on November 22, 2013, the NRC staff issued interim staff guidance document LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” In accordance with the enclosed audit plan, the NRC staff plans to conduct an onsite audit of the service water integrity and fire water system aging management programs during the week of February 22, 2016. If you have any questions, please contact me by telephone at 301-415- 6459, or by e-mail at michael.wentzel@nrc.gov.

Sincerely,

/RA/

Michael J. Wentzel, Project Manager

Projects Branch 2

Division of License Renewal

Office of Nuclear Reactor Regulation

Junk Safety Culture at Hope Creek.

This is caused by poorly designed instrumentation and inadequately trained employees. You catch all the unnecessary scrams and transients at this extremely important three plant resource.

It has to be looked at as contextual with all the other issues at the facility!!!

Reactor Scram Due to Invalid RRCS Actuation

On September 28, 2015, at 20:46, with the Hope Creek reactor operating at 100% power, a human error during surveillance testing resulted in the actuation of the Redundant Reactivity Control System (RRCS), and subsequently, an automatic reactor scram on a valid low water level signal. At the time of the transient, a surveillance test of division 1 of the RRCS system was in progress. The test simulates a high reactor pressure signal. Plant data show the signal was entered in both channels of division 1 of the RRCS system. The resulting system actuation caused a trip of both Reactor Recirculation Pumps, and the actuation of the Alternate Rod Insertion (ARI) function of the RRCS system. As a result of these two actuations, reactor power lowered, causing reactor water level to lower to the Reactor Protection System (RPS) trip set point of +12.5 inches. The RPS initiated an automatic reactor scram. Reactor operators recovered water level to within the desired band using the feedwater system. Reactor pressure was maintained using turbine bypass valves discharging to the main condenser.

CAUSE OF EVENT

The cause of this event is that the technician made an error in the performance of the surveillance test. The error was most likely caused by pressing the incorrect key on the common keyboard for the panel (placing the wrong channel in test). Based on a review of plant data (alarms and indications) and surveillance test simulation on the RRCS training simulator, it was concluded that the technician most likely recognized the unexpected conditions and attempted to correct his error. The technician did not understand that the pressure test signal had sealed in on the incorrect channel. When faced with an unexpected condition, the technician did not stop and seek supervisory guidance .. When the test signal was subsequently entered into the correct channel, the RRCS system actuation resulted. When the cause analysis determined that the cause was associated with a human error, and also determined the most probable error sequence, technician response to further questions could not be obtained, because the technician who was involved had resigned.

Hope Creek's Junk SRV's Pressure setpoint Inaccuracies

Hope Creeks Junk SRVs: Addicted to Normalization of Deviance

Update 1/16 

This excerpt is from a recent letter to me by the NRC's Mr Bower concerning Hope Creek. Is he trying to minimized the extent of the problems with Hope Creeks SRV problems or scrupulously telling us the complete story. Anyone nuclear whether nuclear employees or the NRC should be "sticklers for the details". Why was Mr Bowers Chief, Projects Branch 3, so inaccurate to me? I bet you he went to a spectacular college? Hope Creek over the years have habitually violated their "mechanical stresses on the torus and torus attached piping" (MAPI value). 

NRC official Mr. Bower: "In addition, the increase in mechanical stresses on the torus and torus attached piping due to the higher lift setpoints remained within code acceptable limits."

For some some reason Hope Creek only put a few years worth of "mechanical stresses on the torus and torus attached piping" limits in their LERS. So the red highlighted data below is the times Hope Creek's violated or challenged the "MAPI values"(mechanical stresses on the torus and torus attached piping). Does not disclosing the MAPA values constitutes a cover-up.  

First posting below

**So the last three setpoint inaccuracies LERs had 21 failures. Supposedly they tested 42 valves (3X14). It could be less as they don't often test all fourteen SRVs per outage or report. Get it, 50% failure rate over maybe six years. The tolerable legal failure is 3 over six years. This was all under the plus or minus 3% regime. What failure rate would it be at plus or minus 1%?    

LER 0000-003

*F 3.1% Ion-implanted disc
K 7.8% Disc not implanted

LER 2001-007-00

(psig) (psig) (psig)
F013P 1216 1120 1087 -1153 8.6
F013H 1169 1108 1075 - 1141 5.5
F013D 1182 1130 1096 - 1163 4.6

LER 2003-003-00

(Again erratic testing documentation. There is no more "notes" on seat leakage?) 

(psig) (psig) (psig)
*F013A* 1190 1130 1096 -1163 +5.3 

F013D** 1196 1130 1096 -1163 +5.8
F013E** 1187 1130 1096 -1163 +5
*F013G** 1204 1120 1086 -1154 +7.5 

F013J** 1165 1120 1086 -1154 +4
F013K** 1142 1108 1075 -1141 +3.1
F013L** 1191 1120 1086 -1154 +6.3
F013M* 1150 1108 1075 -1141 +3.8 

* These valves failed due to seat leakage
** These valves failed due to corrosion bonding/sticking of the pilot disc

LER 2004-009-00

(psig) (psig) (psig)
*F013A 1192 1130 1096 -1163 5.5% 

F013B 1171 1130 1096 -1163 3.6%
F013C 1207 1130 1096-1163 6.8%
F013D 1184 1130 1096 -1163 4.8%
*F013F 1156 1108 1075-1141 4.3%

LER 2006-03-00

(psig) (psig) (psig) 

*F013A 1166 1130 1096-1163 3.2%  

F013C 1166 1130 1096-1163 3.2% 

F013K 1144 1108 1075-1141 3.2% 

***This LER below is when they began publishing a value(MAPI value) on the SRV piping stresses (LIMIT). The accident is SRV pipe break between the vessel and torus. It is a very dangerous kind or LOCA or pipe break. They could very quickly heat up primarily containment threating electrical cables and vessel level instrumentations.
Licensee Event Report 2009-002-01

(psig) (psig) (psig) Actual Limit* 

*F013A 1195 1130 1096-1163 5.80% 3.00%  

F013C 1203 1130 1096-1163 6.50% 21.80% 

*F013F 1163 1108 1075-1141 5.00% 5.50%  

F013G 1156 1120 1087-1153 3.20% 8.70% 

F013K 1212 1108 1075-1141 9.40% 22.40% 

F013L 1170 1120 1087-1153 4.50% 16.30%

Licensee Event Report 2010-002-01

(psig) (psig) (psig) Actual Limit' 

*F013A 1177 1130 1096-1163 4.20% 3.00% 

F013C 1186 1130 1096-1163 5.00% 21.80% 

*F013G 1199 1120 1087-1153 7.10% 8.70%  

F013K 1172 1108 1075-1141 5.80% 22.40 

%F013L 1192 1120 1087-1153 6.40% 16.30%F013P 1157 1120 1087-1153 3.30% 27.4%

Licensee Event Report 2012-004-01

(psig) (psig) (psig) Actual Limit  

F013B 1169 1130 1096-1163 3.50% 39.4% 

*F013F 1193 1108 1075-1141 7.70% 5.5%  

F013H 1157 1108 1075-1141 4.40% 37.7% 

F013K 1202 1108 1075-1141 8.50% 22.40%

F013L 1193 1120 1087-1153 6.50% 16.30% 

F013P 1185 1120 1087 -1153 5.80% 27.4% 

(They are really erratic documenting this testing. So now this MAPI value is discontinued(LIMIT))without explanation 

Licensee Event Report 2013-007-00

So the established MAPI value limit on F013A is 3.0% on 2009-002-01 and 2010-002-01 on this LER ,but has no explanation. 

(psig) (psig) (psig) Actual

*** F013A 1170 1130 1096-1163 3.5%  

F013D 1192 1130 1096-1163 5.5% 

F013F 1178 1108 1075-1141 6.3% 

F013K 1149 1108 1075-1141 3.7% 

F013L 1175 1120 1087-1153 4.9%

 Licensee Event Report 2015-004-01

The established "MAPI value" on FO13F in is past LERs (LER 2009-002-01) is 5.0% and in this LER they are in violation on F013F with  setpoint accuracy  of 11.90%. So they are in violation in this LER on setpoint accuracy and SRV piping stress values on F013F. 

(psig) (psig) (psig) Actual 

F013C 1216 1130 1096.1 -1163.9 7.61% 

***F013F 1240 1108 1074.8 -1141.2 11.90% 

*F013G 1208 1120 1086.4 - 1153.6 7.86%F013H 1148 1108 1074.8-1141.2 3.60%
F013J 1161 1120 1086.4 -1153.6 3.66%
F013K 1161 1108 107 4.8 -1141.2 4.80%
F013 L 1165 1120 1086.4 -1153.6 4.00%
F013 M 1207 1108 1074.8 -1141.2 8.90%
F013P 1221 1120 1086.4 -1153.6 9.00%
F013R 1169 1120 1086.4 -1153.6 4.38% 

Special Inspection in 2015 Didn't Fix a Thing at Crap Plant River Bend

I got a special inspection over reactor vessel level control during a scram in 2015 (the mike mulligan River Bend special inspection) special inspection. The problem is they didn't do any scram testing and all the corrective action didn't take effect for many years. ( well, Christmas scram in 2014) (They need to purposely scram a few times with everyone on high alert to watch the plant's and staffs response. Then devise a scheme to fix it fast. Just like initial plant operational testing...)

"During the scram, level 8 occurred immediately"

So here we go again after a special inspection effectively nothing is fixed. Vessel level is just banging around...reactor vessel goes up and down like a mad man and tripping the feed pumps.

Lightning is not suppose to trip a nuclear plant. Did something crap out in their switchyard (fail) during a lightning strike.

When do they become a Pilgrim with too many scams...enhanced inspections because they are banging the whole plant around like level?

Power Reactor	Event Number: 51644
Facility: RIVER BEND Region: 4 State: LA Unit: [1] [ ] [ ] RX Type: [1] GE-6 NRC Notified By: DANIEL PIPKIN HQ OPS Officer: HOWIE CROUCH	Notification Date: 01/09/2016 Notification Time: 07:04 [ET] Event Date: 01/09/2016 Event Time: 02:37 [CST] Last Update Date: 01/09/2016
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(iv)(B) - RPS ACTUATION - CRITICAL 50.72(b)(3)(iv)(A) - VALID SPECIF SYS ACTUATION	Person (Organization): VIVIAN CAMPBELL (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 Shutdown

Event Text

AUTOMATIC REACTOR SCRAM ON MAIN STEAM ISOLATION DUE TO ELECTRICAL FAULT "On 1/9/16 at 0237 [CST], River Bend Station sustained a reactor scram during a lightning storm. An electrical transient occurred resulting in a full main steam isolation [MSIV] (Group 6) and a Division II Balance of Plant isolation signal. During the scram, level 8 occurred immediately which tripped the feed pumps. A level 3 signal occurred also during the scram. Subsequent level 3 was received three times due to isolated vessel level control. The plant was stabilized and all spurious isolation signals reset, then the MSIVs were restored. The plant is now stable in Mode 3 and plant walkdowns are occurring to assess the transient." During the scram, all rods inserted into the core. The plant was initially cooled down using safety relief valves. Offsite power is available and the plant is in its normal shutdown electrical lineup.

Hope Creeks Junk SRVs: Addicted to Normalization of Deviance

Work in progress.

Hope Creek's Junk SRV's Pressure setpoint Inaccuracies

 

Big picture my analysis goes like this. I have been studying this for many years. The NRC won’t disclose what is driving this because it will threaten a tremendous amount of grid electricity across many plants. The industry got themselves backed into a corner. Just think about it, why would these modern corporations tolerate this? These SRVs threatens blowing a lot money, unproductively eating up a lot of resources…another industry would just clear off the decks with bringing on modern equipment. They just get rid of their unproductive headaches and risk. So obviously they are stuck with the SRVs until permanent shutdown. Target Rock and Areva can’t provide SRVs to the USA because of the financial risk with getting blamed with their valves causing a meltdown. They could get sued over many tens of billions of dollars of damages. So where is the governmental insurance if one of their valves caused enormous financial damages? This just might be the result of Fukushima. Remember overheated SRVs, components like valve rubber seals and electrical cable caused the valves to get stuck stuck shut. This primarily caused the meltdown and release of radioactivity. The footprint of Fukushima would have been drastically smaller if the valves were opened. I wonder who supplied the SRVs to Fukushima?

Behind Hope Creek’s SRV problems is they can’t get any legitimate corporation to produce and supply SRVs to these old BWRs. The Corporations are stuck using bailing wire and duct tape (Chinese parts) to keep their SRV operable until permanent shutdown. That is the cover-up.        

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100

KING OF PRUSSIA, PA 19406-2713

December 31, 2015

Mr. Michael Mulligan

P.O. Box 161

Hinsdale, NH 03451

Dear Mr. Mulligan:

I am replying to your calls and emails with Richard Barkley of my staff in November 2015. At that time, you expressed concerns with the as-found test results over the last several years of the two-stage Target Rock safety relief valves (SRVs) installed at Hope Creek. As Mr. Barkley discussed with you, the NRC has been aware of this problem for some time as documented in prior NRC resident inspection reports (e.g., see integrated inspection report 50-354/2013-005). PSEG has reported these issues in LERs for Hope Creek in 2012, 2013 and 2015, and

(Note: the indented material is my add on...this isn't on their letter to me.)

LER 2015-004-01

total of ten of the 14 SRV pilot stage assemblies had setpoint drift outside of the required TS 3.4.2.1 tolerance values of +/-3% of nominal value.

as-found' test results for the ten SRVs not meeting the TS requirements are as follows:

Valve ID As Found TS Lift Setting Acceptable Band % Difference

(psig) (psig) (psig) Actual

F013C 1216 1130 1096.1 -1163.9 7.61%

F013F 1240 1108 1074.8 -1141.2 11.90%

F013G 1208 1120 1086.4 - 1153.6 7.86%

F013H 1148 1108 1074.8-1141.2 3.60%

F013J 1161 1120 1086.4 -1153.6 3.66%

F013K 1161 1108 107 4.8 -1141.2 4.80%

F013 L 1165 1120 1086.4 -1153.6 4.00%

F013 M 1207 1108 1074.8 -1141.2 8.90%

F013P 1221 1120 1086.4 -1153.6 9.00%

F013R 1169 1120 1086.4 -1153.6 4.38%

LER 2013-007-00

A total of five of the 14 SRV pilot stage assemblies had setpoint drift outside of the required TS 3.4.2.1 tolerance values of +/-3% of nominal value. On November 4, 2013, HCGS received a report documenting the failure of SRV 'L.' On November 22, 2013, HCGS received a second report documenting the failures of SRVs 'A', 'D', 'F', and 'K.'  

Valve ID As Found TS Lift Setting Acceptable Band % Difference
(psig) (psig) (psig) Actual
F013A 1170 1130 1096-1163 3.5%
F013D 1192 1130 1096-1163 5.5%
F013F 1178 1108 1075-1141 6.3%
F013K 1149 1108 1075-1141 3.7%
F013L 1175 1120 1087-1153 4.9%

LER 2013-005-00

The cause of the failure of solenoid valve (S/N 481) was determined to be a manufacturer's assembly error. The external vendor found that the anti-rotation pin that secures the adjustable plunger was not installed. Without the pin, the plunger was allowed to rotate and unthread until contacting the internal stop, which prevented the solenoid from picking up when energized. The solenoid coil was in good condition; there was no indication of an internal short. The SOV was reassembled with the plunger re-threaded in place. With the valve body installed back on the solenoid, the SOV could be operated. HCGS determined from the results of the failure analysis that the failure of this SOV occurred at some point during the operating cycle.

LER 2012-004-01

A total of six of the 14 SRV pilot valves experienced setpoint drift outside of the TS 3.4.2.1 limit.

Five of the six SRVs were within the maximum allowable percent increase (MAPI) value. The SRV-F was the only SRV that did not meet the MAPI value. A Technical Evaluation assessed whether the stresses imposed by the increased lift setpoint would have been below the ASME Section III, Appendix F value for failure. The results of the Technical Evaluation are being communicated in this supplemental LER. 

(psig) (psig) (psig) Actual Limit
F013B 1169 1130 1096-1163 3.50% 39.4%
F013F 1193 1108 1075-1141 7.70% 5.5%
F013H 1157 1108 1075-1141 4.40% 37.7%
F013K 1202 1108 1075-1141 8.50% 22.40%
F013L 1193 1120 1087-1153 6.50% 16.30%
F013P 1185 1120 1087 -1153 5.80% 27.4%

following several refueling outages prior to that time. During the resident inspectors’ closeout inspections of the LERs issued by Hope Creek for the as-found setpoint drift of the SRVs, it was noted that PSEG engineering evaluations determined that the reactor vessel overpressure protection was not affected by the SRV pilot valve setpoint drift. Thus the SRVs were capable of performing their design safety function even with the setpoint drift noted. In addition, the increase in mechanical stresses on the torus and torus attached piping due to the higher lift setpoints remained within code acceptable limits. These LER closeouts and the inspectors’ independent assessment of the safety significance of these events were documented in NRC integrated inspection reports 2012-005 and 2014-003.

The issue of setpoint drift as well as the reliability for Target Rock two and three stage safety relief valves installed in Boiling Water Reactors has been of concern to the NRC for many years, and was the subject of Generic Safety Issue B-55, “Improved Reliability of Target Rock Safety Relief Valves.” The resolution of that GSI was published in Regulatory Issue Summary (RIS) 2000-012, a copy of which is available on the NRC

Right, Regulatory Issue Summary 2000-012 is severely obsolete... information at least sixteen year old. Why can't they keep up to industry problems. Where is there a new report on these problems. The stellite and platinum information is also old old information too. The facts are, after putting stellite and platinum in plant, the condition only worsened. All these NRC officials are professional word smiths and highly educated. Why is the agency intentionally fuzzing up the picture they are giving us.

 

website. As noted in that RIS, several actions were taken by the BWR Owners Group and individual BWR licensees to improve the performance of Target Rock SRVs. These actions included: (1) the installation of ion beam implanted platinum or Stellite 21 pilot valve disks, and (2) the installation of additional pressure actuation switches. These changes, coupled with an expanded acceptance range (from +/- 1% to +/- 3%) for SRV setpoint as-found values, have significantly reduced the number of SRV asfound setpoints being outside the specified Technical Specification limit. However, as noted in NRC Information Notice 2006-024 (ML062910111), during offsite vendor testing following refueling outages, SRVs continue to be found with lift setpoints outside the tolerances required by the Technical Specifications for Hope Creek and a number of other BWRs.

In the particular case of Hope Creek, PSEG has taken steps to improve SRV performance, specifically the installation of ion beam implanted platinum or Stellite 21 pilot valve disks, but with limited success to date. PSEG’s prior long-term plan to address setpoint drift was to install SRVs from a foreign vendor that had demonstrated better setpoint performance over time.

Unfortunately, that vendor was not able to meet the performance specifications set by PSEG and that plan was abandoned. PSEG then proposed replacing their two-stage Target Rock SRVs with three-stage Target Rock SRVs due to the three-stage valve performance history of less setpoint drift over time. That plan was suspended shortly before the last refueling outage when another plant in the industry experienced performance issues with the opening of their three stage SRVs and subsequent failure to promptly reclose. Going forward, the NRC plans to continue monitoring and independent oversight of the performance of Hope Creek’s SRVs consistent with the NRC’s Reactor Oversight Process (ROP).

We appreciate your concerns in this matter and recognize that the setpoint drift experienced by the SRVs at Hope Creek continues to recur in spite of prior corrective actions by PSEG. Consistent with ROP guidance and the safety significance of the issue, the NRC will continue to focus inspection resources on this issue to ensure effective, long-term corrective actions are taken by PSEG. Should you have any further questions in this matter, please contact Richard Barkley of my staff at (610) 337-5328.

Sincerely,

/RA/

Fred L. Bower, III, Chief,

Projects Branch 3

Division of Reactor Projects

Cooper and Fort Calhoun potential flooding?

updated 01/05/2016

 


The weather and flooding is so odd for this time of year with the blockbuster El Nino, they should put the Cooper and Fort Calhoun on a flooding emergency footing. Basically assume plant flooding is going to occur beginning before summer 2016.

NRC Keeping an Eye on Water Levels along the Mississippi and Missouri Rivers

Victor Dricks
Senior Public Affairs Officer, Region IV

Heavy rains and subsequent flooding across America’s heartland are being carefully watched by the NRC and the operators of nuclear power plants located along the Missouri and Mississippi Rivers, although none of the plants are expected to be adversely affected.

Flooding is one of the many natural hazards that nuclear power plants must be prepared for. As a condition of their operating license, every nuclear power plant must demonstrate the ability to withstand extreme flooding and shut down safely if necessary – requirements that have been updated and strengthened following the Fukushima accident in 2011.

According to the National Weather Service, the threat of significant flooding is expected to persist for another two weeks in parts of Nebraska, Missouri, Arkansas, Mississippi and Louisiana – all states with operating nuclear power plants. Each of these plants has emergency diesel generators that can supply backup power for key safety systems if off-site power is lost. And all plants have robust designs with redundancy in key components housed in buildings with watertight doors.

In Nebraska, water levels are high along the Missouri River in the vicinity of Fort Calhoun and Cooper Nuclear Station, but not high enough to require any mitigating actions by plant operators.

In Missouri, the Callaway plant is not expected to be affected by any of the heavy rains and flooding that have plagued other parts of the state.

Arkansas Nuclear One, in Russellville, has not been affected by heavy rains and no impact is predicted. But some local roads that lead to evacuation routes were flooded, prompting local law enforcement officials to post detour signs.

At Grand Gulf in Mississippi, levels on the Mississippi River continue to rise, with a crest expected on January 15. The projected river levels, however, are not expected to have any effect on site operations.

At River Bend in Louisiana, the situation is similar. There, the Mississippi River level is expected to peak on January 18, at a level that will not affect site operations. Further downstream, levels on the Mississippi River near the Waterford nuclear plant are expected to crest at a level two feet below where the operator would need to take some actions at the site.  

Two feet is not a lot of wiggle room...

Richard Smith, the Acting Chief of Region IV’s Response Coordination Branch, said his staff is getting periodic updates from the National Weather Service on conditions that might affect any of the region’s nuclear plants. Additionally, the NRC is relying on its resident inspectors, who live in the communities near the plants where they work each day, to independently verify that precautionary flooding procedures taken by plant operators are being properly implemented.

“We’re following events closely here in the Region,” Smith said, “and if anything changes significantly our on-site inspectors will be able to confirm that the operators are taking appropriate protective actions.”

Reposted from 12/30/2015

These plants are on the Missouri River in the vicinity of the Omaha Nebraska. There is no threat of flooding in this area at the present time. The great midwest 1993 flood everyone speaks  about and the great flood in 2011 at Fort Calhoun developed in the early spring and summer. This late 2016 flooding is coming from a gigantic El Nino event. Most of the flooding at Fort Calhoun in 2011 basically came from precipitation in upper Montana, South Dakota, North Dakota, Wyoming and surrounding. Most of the flooding today seems to be focused 400 miles southeast at St Louis Missouri.

Based on this gigantic and still developing El Nino, we'd be in trouble if the extreme precipitation area blossoms out and moves North of Omaha. 

Who knows what late spring and summer 2016 will look like. In Hinsdale NH it has been extremely warm and snowless until  Dec 28. We got less than 2 inches so far. 

    

Waterford's Systemic Falsification of Documents Again

Updated 1/2/2016:

Think of the tough shape Entergy-Louisiana was last year at this time of the year. River Bend just had a complicated scam on Christmas morning in 2014. A whistleblower (me) was going into action later getting a special inspection over poor reactor water level control. Then a month later on Jan 21, 2015 another whistleblower comes to light  at Waterford leading to the widespread falsification of documentation over fire watches.

So they most have had issues with having adequate engineered fire protection, that is the reason for the fire watches. Then on top of poor engineering fire protection they have widespread falsification of the fire watches.
 
I am irritated I can't put the whole informant inspection report on the internet. Its in a form that is not capable...write protected.
 
I don't like Alternate Disputes Resolution (ADM) program. It allows these guys to go behind closed door. It delays outsiders knowledge with what is going on for years.
 
Typically a violation level depends how risk full the event is.  They look at all the people and equipment that was degraded then come up with a calculation with the probability of the accident within just the specific event they are looking at. This calculation is basically a black box nobody understand least the outsiders. They count just a fraction of the actual risk.
 
See, I see this as systemic falsification of documentation. We have no idea now if the plant is configured or aligned as per plant licensing and within all NRC regulation. Just don't trust them to tell the trust and cold bloodily lying to us. The worst case of this is all the safety systems are turned off and their is nothing but poor quality equipment throughout the plant. It is a very dangerous accident. When you find a plant in this condition you punish them severely, so other won't go down they wrong path.
 
You notice how they keep the unbelievably valuable shift supervisor or highest boss at the plant away from fire watch issue.  It is his job to make sure the plant stays safe...he makes sure the plant always comports to all plant licensing, corporate rules and NRC rules. He has a tremendous amount of authority to get this job done. You get it, all the senior licensed leadership is implicated in a cover-up and lacking integrity.  They all need to get fire. They all had access to uncovered this issue when this started. You wipe out the senior on shift licenses leadership, then you can't operate the plant. This is why the on shift senior management is extremely valuable and why the NRC protects these guys through the political system. Integrity issues, cover-up and widespread falsification issues are the weak link is safety in these nuclear plant and these extraordinarily complex machines and bureaucracy.  
 
Further, according to the NRC, it is extremely hard to accuse senior management with cover-up, integrity and falsification issues. Basically three perfect proof's of falsification and cover-up isn't enough to get some banned from the industry. You need the crook to admit they falsified something, any stupid excuse is acceptable...basically there is very little legal controls with enforcing ethical behavior.
 
Everyone knows these fire watch employees are low paid, poorly trained and generally come from the bottom dregs of our society. Competent management would assume these guys need to be continuously scrutinized. They pay contractors to provide these fire watch employees. It is not like these are plant employees. So senior management sets up a wall in this system, they can't read the credibility of these fire watch employees. Sometimes these jobs are for loser senior management children and relatives...basically do nothing jobs.
 
You can do a lookup on temporary fire watches in the nuclear industry. There is NRC findings and violations all over the industry with temporary fire watches gun decking their rounds. It is a extraordinary mind numbing boring and menial job for losers. The industry has a lot of information about these temporary fire watch jobs...these jobs with their loser temportary employees are highly susceptible to fire watch rounds gun decking across the board. It happened many times at nuclear power plant. A senior plant manager should be extraordinarily specious these temp garbage jobs and poor quality employees...if his job is out to protect the reputation of his companies.
 
A properly engineered fire protection system constantly undated with new tech) with their instrumentation is a lot more reliable than mortal humans.  

Original post
 
Here is the inspection report.

Basically it took a whistleblower to bring this to light.

 Waterford IR 2015011

This is no surprise to me?

So why is this plant even running. They should be shut down for at least 6 months to a year.

The systemic discovery of nuclear plant staff credibility issues should be automatically called a red finding...

Waterford 3 contractors falsified inspection records

Faked fire inspection records for 10 months, NRC says

Anna Thibodeaux
3 hours ago                                                                                                                                                

A U.S. Nuclear Regulatory Commission (NRC) investigation found contractors at Entergy Waterford 3 nuclear power plant in Killona failed to perform fire inspections and falsified records for at least 10 months to show the inspections occurred. 

The NRC says it even found documentation showing a contract worker admitted to sleeping instead of performing an inspection, but records showed it had been done.
On Tuesday (Dec. 22), Entergy spokeswoman Leanna Weaver said Entergy Nuclear is acting on these violations. 

“Although we cannot discuss specific measures taken with individuals beyond the NRC’s release, we can say all involved have faced disciplinary action,” Weaver said. “It is important to note that Entergy identified these issues, notified regulators, fully investigated the issue and took the appropriate actions.”   

The NRC’s Dec. 14 letter to Michael Chisum, site vice president of Entergy Operations in Killona, states its 15-month investigation found Entergy’s contract workers who do the inspections and an Entergy Operations supervisor “deliberately failed to identify and take corrective actions upon being provided with information of suspected wrongdoing by contract fire watch individuals.” 

Entergy identified the company that provided the fire watch workers as GCA Contractors. 

The NRC has given Entergy the option to meet with the federal agency or seek an alternative dispute resolution to discuss corrective actions before it decides enforcement penalties. 

Weaver said Entergy is “not able to respond publicly about our decision on how to address the violations.” 

But she added, “Entergy Nuclear does not tolerate this form of behavior among employees or contractors in any way, and we have robust systems and processes in place to prevent and uncover inaccuracies, whether intentional or not, in documentation. Trust, honesty and integrity are among the key platforms to which all our employees must commit and adhere to.” 

According to the NRC investigation conducted Feb. 3, 2014 to May 19 with contract and licensee personnel, investigators found a manager with the contracting firm that provided the fire inspection workers had “deliberately provided incomplete and inaccurate information to an access authorization reviewing official regarding the trustworthiness and reliability of a contract fire watch individual.” 

Investigators also found instances of seven contract workers who “deliberately failed to conduct compensatory hourly fire watches, as required by site procedure, and falsified fire watch tour logs by initialing that fire watches were performed with knowledge that watches had not been performed.” 

A fire watch or inspection requires each area or room be assessed to ensure fire doesn’t occur in parts of the large nuclear plant building housing equipment operating the nuclear reactor. The NRC requires the inspections, a fire watch log and record of any fire hazards, as well as requires  record of any adverse condition that have been identified. 

The letter also states NRC found “one Entergy Operations Inc. supervisor deliberately failed to identify and take corrective actions upon being provided with information of suspected wrongdoing by contract fire watch individuals.” On Jan. 21, 2014, the NRC says it received information indicating an issue with the fire inspections. 

Additional information was  received that “a Waterford Steam Electric Station security officer questioned fire watch personnel about the absence of a door alarm that is usually received on a security door when rounds are conducted. The security officer’s concern led to the licensee reviewing card reader information for the rounds, which identified numerous instances of the fire watch tours not being conducted; although the surveillance records indicated that the tours had been completed.” 

Seven days later, the Office of Investigations initiated an investigation to determine if fire protection personnel had willfully falsified surveillance records. 

The investigation was aimed at determining if personnel - contract and company - had deliberately falsified fire watch records and if management was part of this effort.Completed on May 19, the investigation indicated three employees “acknowledged the standard for falsification and admitted to falsifying the records,” according to the NRC. 

Another three inspection individuals denied wrongdoing, but door alarm records verified missed inspections by these same three people. 

NRC also maintains Entergy Operations personnel failed to implement fire protection procedures. 

“Seven fire watch personnel failed to conduct numerous observations and inspections of various fire areas to assess for indications of fires,” states the NRC letter to Entergy.A company superviser “admitted that the condition was not properly documented and addressed when the concern was brought to his attention.

Relevant Generial Nuclear Industry Comment

A couple weeks ago you asked me for my opinion of root of plant problems, and I mention plant management and greed.

It dawned on me of another problem

With all the top down decision making, 10 + 10 = 100, just sign here or else,

I am thinking a lot of good technical people are probably not projecting working at the same place for 40 years and retiring.  Having good people stay for 40 years gives a lot of continuity and tribal knowledge, lessons learned etc.

If they are all planning an exit strategy, they do not care.  No need for attention to detail and accountability.  They will be gone and someone else will have to pick up the pieces.

So management comes around wanting you to sign this 10 + 10 = 100, sure, no problem.  I am planning on leaving in a month to a new job, it will take 3 months before anyone realizes the 100 is wrong.

Accountability and responsibility