Clinton 50.59

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 
This issue was a
  

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

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

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

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

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

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

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

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

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

INSPECTION REPORT05000461/2015008

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

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

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

Millstone

???

Palisades Plant Is Such A Dog: NRC Finally Says Palisades has A Pattern Of PCP Pump problems

May 2014: Finding a chunk of PCP impeller lodged in the core barrel inspection report. 

Issues of concern:

1) You see with the PCP seal and the  CCW seal the pattern of not following procedures and bum procedures.This place and the NRC reeks with the smell of procedure problems.

2)  With the safety injection tank, this is on the NRC with letting them get away with leaks from 2010. Hasn't anyone learned the lessen with the safety injection/refueling water tank. Basically making assumption on incomplete information...this is a pattern with thee guys.

3) I have issues the of the timelessness of the of the PCP seal failure.     

April 30, 2015:  PALISADES NUCLEAR PLANT NRC INTEGRATED INSPECTION REPORT

05000255/2015001

***Green. A finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1(a) was self-revealed when the ‘C’ primary coolant pump (PCP) seal degraded as a result of an inadequate maintenance procedure. Specifically, maintenance procedure PCS–M–54, “N–9000 Primary Coolant Pump Shaft Seal Assembly,” did not identify critical steps in the assembly of the PCP seal and, as a result, the work activity was not adequately controlled. This issue was entered into the licensee’s Corrective Action Program (CAP) as CR–PLP–2014–03495, Planned Outage Required Due to Two Stages of the Primary Coolant Pump P-50C Seal Not Performing as Expected, dated June 21, 2014.

***Green. A finding of very low safety significance and an associated NCV of TS 5.4.1(a) was self-revealed on January 6, 2015, after the licensee identified smoke coming from the ‘C’ component cooling water (CCW) pump (P–52C) as a result of incorrect assembly of the inboard pump bearing in December 2014, due to an inadequate maintenance procedure. This issue was entered into the licensee’s CAP as CR–PLP–2015–00063, Workers Reported Smoke Coming from Shaft of P–52C, dated January 6, 2015. Inoperability of Safety Injection Tank Due to Long-Term Leakage

Introduction: A finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” was identified by the inspectors when licensee personnel failed to ensure that leakage out of the ‘B’ SIT, a condition adverse to quality, was corrected in a timely manner. Specifically, although minor water leakage out of the ‘B’ SIT had been occurring since at least 2010, the licensee failed to adequately address the leakage despite several plant outages that provided an opportunity to perform maintenance.

***Green. A finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion XVI, “Corrective Action,” was identified by the inspectors when licensee personnel failed to assure that leakage out of the ‘B’ safety injection tank (SIT), a condition adverse to quality, was corrected in a timely manner. Specifically, although minor water leakage out of the ‘B’ SIT had been occurring since at least 2010, the licensee had not corrected the leakage despite several plant outages that provided an opportunity to address the issue. This issue was entered into the licensee’s CAP as CR–PLP–2014–04861, B SIT Declared Inoperable Due to Reaching Technical Specification Low Level Setpoint, dated October 7, 2014

***Green. A finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion III, “Design Control,” was identified by the inspectors when the licensee credited fire doors for High Energy Line Break (HELB) protection without a supporting test or evaluation. Specifically, Procedure 4.02 credited fire doors with protection of safety-related equipment against a HELB when the primary HELB barrier was disabled without a test or evaluation to demonstrate the doors could withstand the HELB environment. This issue was entered into the licensee’s CAP as CR–PLP–2015–00371, NRC Concerns with Calculation EA–PSA–CCW–HELB–02–17, dated January 22, 2015.

Severity Level IV. A Severity Level IV NCV of 10 CFR 50.59(d)(1), “Changes, Tests, and Experiments,” and an associated finding of very low safety significance was identified by the inspectors when licensee personnel failed to maintain a written safety evaluation that provided a basis that the use of temporary alligator clip jumpers to maintain emergency diesel generator (EDG) operability during certain maintenance activities did not require a license amendment. Specifically, the licensee did not address the adverse effects of the use of alligator jumpers on the design and qualification of the diesel generator (DG) circuit breaker used per Engineering Change 50310 and changes to procedure SPS–E–1, “2400 Volt and 4160 Volt Allis Chalmers and Siemens Vacuum Circuit Breaker Auxiliary Switch Adjustments,” Revision 34. This issue was entered into the licensee’s CAP as CR–PLP–2014–04859, NRC Identified 50.59 Issue, dated October 7, 2014.

***Severity Level IV. A Severity Level IV NCV of 10 CFR 50.59(d)(1), “Changes, Tests, and Experiments,” and an associated finding of very low safety significance was identified by the inspectors when licensee personnel failed to maintain a written safety evaluation that provided a basis that the use of temporary alligator clip jumpers to maintain emergency diesel generator (EDG) operability during certain maintenance activities did not require a license amendment. Specifically, the licensee did not address the adverse effects of the use of alligator jumpers on the design and qualification of the diesel generator (DG) circuit breaker used per Engineering Change 50310 and changes to procedure SPS–E–1, “2400 Volt and 4160 Volt Allis Chalmers and Siemens Vacuum Circuit Breaker Auxiliary Switch Adjustments,”

This should have been 50.59 and indicates 50.59 violations are more widespread than known. It is a failure of the NRC enforce regulations (50.59s).

Revision 34. This issue was entered into the licensee’s CAP as CR–PLP–2014–04859, NRC Identified 50.59 Issue, dated October 7, 2014. 

More primary coolant problems...so now for the first time the NRC admits there is a pattern with numerous PCP issues?  

Selected Issue Follow-up Inspection: Primary Coolant Pumps

a. Inspection Scope

The inspectors have documented several issues related to PCPs at Palisades over the past several years. The inspectors documented completion of an Operability Determination inspection sample that reviewed increased vibrations on the ‘C’ PCP in IR 05000255/2011005. A Green finding and associated NCV was documented in Section 1R15.b of IR 05000255/2012003 for the operation of PCPs outside their design operating criteria. Another Operability Determination inspection sample was documented in IR 05000255/2013002, which reviewed an oversized PCP impeller. The inspectors documented completion of a post-maintenance testing inspection sample following replacement of the ‘C’ PCP impeller in Section 1R19 of IR 05000255/2014002. Section 1R20 of that same IR documented a comprehensive review of the history of PCP issues at Palisades and the review of a piece of PCP impeller that was unable to be removed from the reactor vessel. The inspectors documented completion of another Operability Determination inspection sample that reviewed degradation of the ‘C’ PCP seal in IR 05000255/2014003. Section 1R20 of that same IR documented that the licensee performed a maintenance outage to replace the degraded ‘C’ PCP seal and Section 4OA2.4 documented a review of the licensee’s planned actions to address the NCV documented in 2012.

During this inspection period, the inspectors continued their collective and ongoing review of the numerous PCP issues at Palisades. Of particular focus was a review of the licensee’s root cause evaluation for degradation of the ‘C’ PCP seal that was initially installed during refueling outage 1R23 in spring 2014 and replaced during a summer 2014 maintenance outage. The inspectors also remained aware of the licensee’s plans and progress in resolving the NCV issued in 2012, and planned to continue to assess the timeliness of corrective action implementation.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152–05.

b. Findings

Inadequate Procedure Leads to Primary Coolant Pump Seal Degradation

Introduction: A finding of very low safety significance (Green) and an associated NCV of TS 5.4.1(a) was self-revealed when the ‘C’ PCP seal degraded as a result of an inadequate maintenance procedure. Specifically, maintenance procedure PCS–M–54, “N–9000 Primary Coolant Pump Shaft Seal Assembly,” did not identify critical steps in the assembly of the PCP seal and, as a result, the work activity was not adequately controlled.

Description: During RFO 1R23, from January through March 2014, the ‘C’ PCP seal was replaced as a planned maintenance activity. Prior to the RFO, the vendor provided training to plant maintenance personnel on seal disassembly, assembly, and installation. The seal package was assembled by site personnel using procedure PCS-M-54, “N–9000 Primary Coolant Pump Shaft Seal Assembly,” Revision 6, on the spent fuel pool floor with oversight from the vendor. This activity also included pre-installation testing and cleaning. The seal was then lifted into containment and installed in the pump.

On March 16, 2014, a few days after plant startup from RFO 1R23, the licensee identified that the ‘C’ PCP seal package breakdown pressures for the middle and lower stages were not trending as expected. An operational decision-making instruction (ODMI) was written to provide guidance to the operators on steps to take if the pressures increased, the pressure breakdowns between the seals decreased, or the controlled bleed-off flow increased. On May 13, 2014, following safety injection system surveillance testing, the control room received an alarm for ‘C’ PCP seal abnormal pressure and entered the abnormal operating procedure (AOP). This also exceeded trigger points in the ODMI. The middle seal stage was declared failed and an engineering evaluation was performed to determine the condition of the remaining seals and if the pump could continue to operate safely. The pump was deemed safe for continued operation and the ODMI trigger point criteria were revised based on the most recent data.

Based on continued slow but steady seal degradation, the

The transient of shutdowns cause damage to safety equipment.

licensee decided to shut down the plant on June 21, 2014, to replace the seal. The transient of shutting down the unit caused the lower stage of the seal to fail, as well as the previously declared failed middle stage. The upper and vapor stages of the seal remained fully functional. After the seal package was replaced, the unit was re-started from the maintenance outage on June 26, 2014. The licensee entered this issue into the CAP as CR–PLP–2014–03495, PCP P–50C Seal Cartridge Exceeded ODMI Minimum Pressure Drop for Two Stages,

on June 24, 2014.

A root cause evaluation was conducted to determine the cause of the seal stage failures. The removed seal was sent to the vendor for analysis after it was removed. The vendor was able to rule out many potential causes including the seal being dropped, inappropriately pressurizing the seal, increased or abnormal pump

My theory was the big impeller blade missing could damage pump bearings the bearing due to excess vibration. The C pump is the same pump with impeller missing and the seal damaged.    

vibrations, and foreign material intrusion. Interviews with maintenance personnel were also conducted. The direct cause was determined to be the stationary faces for the middle and lower stages of the seal not being sufficiently seated to allow the o-ring to seal and thus allowing leakage through the stages past the o-rings. No definitive root cause was determined. However, a probable root cause of not classifying the seal assembly as a critical maintenance activity, which would have provided additional training, oversight, and critical step identification, was identified. There was also a misunderstanding of the pre-installation testing; the licensee believed this testing would identify any assembly issues, when in fact it would only detect gross leakage or major assembly errors.

Analysis: The inspectors determined that not maintaining an adequate procedure to assemble and install the ‘C’ PCP seal was an issue of concern and evaluated the issue in accordance with IMC 0612, Appendix B. The issue of concern was not associated with any willful or traditional enforcement aspects. The inspectors determined that the issue of concern was within the licensee’s ability to foresee and correct and represented the failure to meet a standard in that the licensee did not maintain appropriate maintenance procedures as recommended in Regulatory Guide 1.33, Revision 2, Section 9.a, which the licensee was committed to in TS 5.4.1(a). Therefore the issue of concern represented a performance deficiency.

The inspectors determined that the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors evaluated the issue in accordance with IMC 0609, Attachment 4. The questions in Table 3 were answered "No" and the inspectors continued the significance evaluation in accordance with IMC 0609, Appendix A. The inspectors reviewed the Initiating Events questions in Exhibit 1 and answered "Yes" to the Loss of Cooling Accident (LOCA) Initiators screening question, “After a reasonable assessment of degradation, could the finding result in exceeding the reactor coolant system leak rate for a small LOCA,” because the first two seal stages ultimately failed and if the 3rd stage had failed, a PCP seal LOCA may have occurred resulting in a small break LOCA. Therefore, a detailed risk evaluation was performed by a Region III SRA.

The change in risk for this performance deficiency was best characterized by the risk associated with the manual reactor shutdown that occurred. The SRAs performed the analysis using the Palisades SPAR Model Version 8.20, SAPHIRE Version 8.1.2.0. A “Transient” initiating event analysis was run using the SPAR model. The result was an estimated conditional core damage probability (CCDP) of 4.17E–07. The CCDP result included risk due to Anticipated Transient Without Scram (ATWS) scenarios. The SRAs reviewed the results that did not contain reactor protection system failures, and obtained a revised CCDP for non-ATWS transients of 1.81E–08. Given this result, the SRAs concluded that the change in risk for the performance deficiency was less than 1E–07/year (i.e., ΔCDF < 1E–07/year). The dominant sequence involved a transient with failure of safety valves to reclose after opening, failure of shutdown cooling, and

failure of high pressure recirculation.

Based on the detailed risk evaluation, the inspectors determined that the finding was of

very low safety significance (Green).

This finding had a cross-cutting aspect in the Work Management component of the Human Performance cross-cutting area. Specifically, the licensee did not effectively screen the PCP seal assembly through the work management process to identify that it should have been classified as a critical maintenance activity. In addition, insufficient emphasis was placed on in-field vendor oversight during work execution. (H.5) Enforcement: Technical Specification 5.4.1(a), states, in part, that written procedures shall be established, implemented, and maintained as recommended in Regulatory Guide 1.33, Revision 2, dated February 1978. Section 9.a, “Procedures for Performing Maintenance,” states in part, “Maintenance that can affect the performance of safety related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.” Procedure PCS–M–54, “N 9000 Primary Coolant Pump Shaft Seal Assembly,” Revision 6, contained instructions for assembly of safety-related PCP seals.

Contrary to the above, during RFO 1R23, maintenance personnel completed assembly of the ‘C’ PCP seal using procedure PCS–M–54, which did not include critical steps to validate that the seal was assembled correctly prior to operation. As a result, the ‘C’ PCP seal stages degraded during plant operation such that a subsequent plant outage was necessary to replace the seal. Because this issue was of very low safety significance and because it was entered into the CAP as CR–PLP–2014–03495, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000255/2015001–07, Inadequate Procedure Leads to Primary Coolant Pump Seal Degradation)

Millstone Nuke Pant Can't Keep Their Safety Doors Functional?

Date of first incident 12/12/2014

Simple Door Latch Sticking Problem At Millstone, Indicates A Bigger Problem?

Date of second incident  2/19/2015

Licensee Event Report (LER)2015-001-00

1. FACILITY NAME 2. DOCKET NUMBER 3. PAGE

Millstone Power Station Unit 3 05000423 1 OF 3

4. TITLE

Unlatched Dual Train HELB Door Results in Potential Loss of Safety Function

5. EVENT DATE 6. LER NUMBER 7. REPORT DATE 8. OTHER FACILITIES INVOLVED

SFACILITY NAME DOCKET NUMBER

MO YEAR YEAR SEQUENTIAL REV MONTH DAY YEAR F 05000

MONTH DY YA YER NUMBER NO.05 0

FACILITY NAME DOCKET NUMBER

02 19 2015 2015- 001 00 04 20 2015 05000

9. OPERATING MODE 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check all that apply)

[1 20.2201(b) El 20.2203(a)(3)(i) [E 50.73(a)(2)(i)(C) [I 50.73(a)(2)(vii)

[1 20.2201(d) El 20.2203(a)(3)(ii) El 50.73(a)(2)(ii)(A) El 50.73(a)(2)(viii)(A)

1E 20.2203(a)(1) El 20.2203(a)(4) 0l 50.73(a)(2)(ii)(B) [I 50.73(a)(2)(viii)(B)

[_1 20.2203(a)(2)(i) El 50.36(c)(1)(i)(A) [1 50.73(a)(2)(iii) E- 50.73(a)(2)(ix)(A)

10. POWER LEVEL [E 20.2203(a)(2)(ii) El 50.36(c)(1)(ii)(A) [E 50.73(a)(2)(iv)(A) El 50.73(a)(2)(x)

ID 20.2203(a)(2)(iii) [E 50.36(c)(2) El 50.73(a)(2)(v)(A) El 73.71(a)(4)

10 20.2203(a)(2)(iv) El 50.46(a)(3)(ii) El 50.73(a)(2)(v)(B) El 73.71(a)(5)

1E 20.2203(a)(2)(v) [1 50.73(a)(2)(i)(A) El 50.73(a)(2)(v)(C) El OTHER

El 20.2203(a)(2)(vi) El 50.73(a)(2)(i)(B) [ 50.73(a)(2)(v)(D) Specify in Abstract below or in

___________________ ___________________________ ___________ ______________N__C___oNRCForm66A

12. LICENSEE CONTACT FOR THIS LER

LICENSEE CONTACT TELEPHONE NUMBER (Include Area Code)

William D. Bartron, Supervisor Nuclear Station Licensing 1 (860) 444-4301

13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT

CAUSE SYSTEM COMPONENT MANU- REPORTABLE CAUSE SY MANU- REPORTABLE

FACTURER TO EPIX C FACTURER TO EPIX

14. SUPPLEMENTAL REPORT EXPECTED 15. EXPECTED MONTH DAY YEAR

On February 19, 2015, with Millstone Power Station Unit 3 (MPS3) at 100% power and in operating mode 1, an individual on a fire watch rove processed through a dual train high energy line break (HELB) door normally and upon checking the door after passage the individual noted the door did not latch. The Control Room was promptly notified. An operator was dispatched to investigate. The operator exercised the door lock-set mechanism freeing the latch allowing the door to properly latch. The door was inoperable for approximately 7 minutes. Technical Specification 3.0.3 was entered and exited appropriately.

Although no definite failure mechanism was identified, the door was experiencing high usage due to compensatory fire watch roves entering/exiting the door. The door lockset mechanism was manually manipulated and then tested several times satisfactorily by maintenance personnel. Further, the door design has the door swing such that the HELB event would act to open the door when the lockset mechanism fails. Engineering is evaluating the adequacy of the preventive maintenance frequency. Additionally, a design change to reverse the door swing such that the HELB event would cause the door to close and thus not rely on the lock-set mechanism is being considered. Additional corrective actions are being taken in accordance with the station's corrective action program.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(v)(D), as a condition that could have prevented the fulfillment of a safety function for systems needed to mitigate the consequences of an accident.

1. EVENT DESCRIPTION:

On February 19, 2015, with Millstone Power Station Unit 3 (MPS3) at 100% power and in operating mode 1, an individual on a fire watch rove processed through a dual train high energy line break (HELB) door normally and upon checking the door after passage the individual noted the door did not latch. The Control Room was promptly notified. An operator was dispatched to investigate. The operator exercised the door lock-set mechanism freeing the latch allowing the door to properly latch. The door was inoperable for approximately 7 minutes. Technical Specification 3.0.3 was entered~and exited appropriately. This event was reported to the NRC pursuant to 10 CFR 50.72(b)(3)(v)(D), (NRC event # 50836) as a condition that could have prevented the fulfillment of a safety function for systems needed to mitigate the consequences of an accident. This event is also being reported pursuant to 10 CFR 50.73(a)(2)(v)(D), as a condition that could have prevented the fulfillment of a safety function for systems needed to mitigate the consequences of an accident.

BACKGROUND:

This door fulfills the requirements of a Security Door, Technical Requirement Manual Fire Door, C02 Door, Dual Train Protection Door, and a HELB Door. It is a key card actuated door with a crash bar on one side and a thumb latch on the other side. The door is part of the HELB barrier for the A and B 480 volt switchgear.

2. CAUSE:

Although no definite failure mechanism was identified, the door was experiencing high usage due to compensatory fire watch roves entering/exiting the door. Further the door design has the door swing such that the HELB event would act to open the door when the latch fails.

3. ASSESSMENT OF SAFETY CONSEQUENCES:

Given the low likelihood of an Auxiliary Building HELB occurring during the time the door was not properly latched (7 minutes), the consequences of this event was of very low safety significance.

4. CORRECTIVE ACTION:

Since this event occurred on the back shift, a maintenance technician was called in to inspect the door lock-set mechanism and affect any necessary repairs. The technician reported his inspection was satisfactory. He exercised the door lock-set mechanism from both the crash bar and the thumb release mechanisms approximately 30 times without any repeat indications of the latch sticking or not functioning. He also noted he tightened one screw on the mechanism that he found loose during this inspection. Continued exercises of the door mechanism after tightening the screw showed no difference in the smooth and proper operation of the door lockset mechanism. It was identified that the door was experiencing high usage due to compensatory fire watch roves entering/exiting the door. Equipment repairs have been completed eliminating the need for this high frequency fire rove activity. Additionally, the preventive maintenance for the door lock-set mechanism has been changed.

A design change to reverse the door swing such that the HELB event would cause the door to close and thus not rely on the lock-set mechanism is being considered.

Additional corrective actions are being taken in accordance with the station's corrective action program.

5. PREVIOUS OCCURRENCES:

* MPS3 LER 2014-004-00, Unlatched Dual Train HELB Door Results in Potential Loss of Safety

Function.

6. Energy Industry Identification System (EIIS) codes:

* Door- DR

* Switchgear - SWGR

Pilgrim's Fuel Vendor Depended On Non Safety Equipment For Core Safety

Basically generic letter 89-19 worries about a non safety system protecting a reactor core. Their concerns relate to: 

1) Redundant and diverse power supplies to these non safety system. 

2) The non safety systems components come up nuclear safety quality.

This document don't give any assurance Pilgrim meets these nuclear safety needs as stated in GL 89-19.

I had problems with River Bend scrams...they always were over feeding the vessel on scrams testing the MFP trips. You are not as habit allow to kept testing protection system...you are supposed control the situation. 

So how often is this going on at other plants and do these guys get to be intentionally evasive to skirt government safety rules. 

You know what bothers me the most, Pilgrim doesn't have total control of safety at the site. The fuel vendor and Pilgrim were like ships passing each in the night without seeing each other.  

April 13, 2015U.S. Nuclear Regulatory Commission 

ATTN: Document Control DeskWashington, DC 20555-0001SUBJECT: Correction of Information Provided in a Response to a Request forInformation Related to Feedwater Pump Trip Technical Specifications(TAC No. M474981)Entergy Nuclear Operations, Inc.Pilgrim Nuclear Power StationDocket No. 50-293License No. DPR-35 

REFERENCE: Boston Edison Company letter to NRC, "Pilgrim Nuclear Power Station Response to Feedwater Trip Technical Specifications (TAC No.M474981), dated October 3, 1994 (BECo Ltr. #94-120) 

Dear Sir or Madam: 

This letter corrects information previously provided to the U.S. Nuclear Regulatory Commission (NRC) in response to a request to submit reactor vessel overfill protection Technical Specifications. 

Specifically, Pilgrim Nuclear Power Station (PNPS) staff identified that a Boston Edison Company letter to the NRC dated October 3, 1994 contained two incorrect statements concerning the function of the feedwater pump trip and how it was credited in the station's safety analysis. The correspondence was related to PNPS' response to Generic Letter 89-19, Request for Actions Related to Resolution of Unresolved Safety Issue A-47 "Safety Implication of Control Systems in LWR Nuclear Power Plants" Pursuant to 10 CFR 50.54(f) and directly responded to NRC's request for information on PNPS' plans to add a Technical Specification requirement for the feedwater pump trip.The October 3, 1994 letter stated, "It can therefore be seen

If the Feed water trip was safety related, does that mean they would have to up grade the safety quality of the Feedwater trip instrumentation. Was Pilgrim basically lying to the NRC to save money, and the NRC approving it being less than truthfully.

that this trip is a plant design feature incorporated to protect equipment, but has no nuclear safety-related function." It further stated "The MFP (Main Feedwater Pump] trip is not credited for fuel protection in any design basis accident or abnormal operational transient described in Pilgrim's Updated Final Safety Analysis Report." However, even though it was PNPS' intent not to credit the trip consistent with the assertions in the letter, while evaluating a condition reported in the PNPS corrective action program in late 2014, station staff discovered that the reload analysis conducted by the nuclear fuel vendor, in fact, had credited the trip in the plant-specific transient analysis for many cycles of operation, including the current cycle. Since the fuel vendor performs this analysis, PNPS staff were unaware that this assumed trip actually terminated the transient and reduced the maximum Critical Power Ratio impact calculated for the event. In Cycles 15 through 20, PNPS input to the transient analysis clearly stated that this trip was not an available feature for transient analysis use by the fuel vendor. 

Following discovery, PNPS took actions to ensure for the remainder of Cycle 20 that Turbine Control Valve Fast Closure and Turbine Stop Valve position scrams were active at power levels exceeding 25%, consistent with the use of thermal limits used by 3D Monicore to ensure thermal limit protection for analyzed transients. These actions were formalized in an Operations department Standing Order. PNPS also completed its evaluation of the cause for the discrepancy between PNPS' intent to not credit the high-level feedwater pump trip and the fuel vendor's calculation input assumptions. The cause was that there was no means specified for direct verification of inputs used by the fuel vendor. Additionally, PNPS evaluated the past three years of operation using the more restrictive Minimum Critical Power Ratio and Linear Heat Generation Rate limits calculated for Cycle 20 if the feedwater pump high-level trip is not credited and concluded that there were no thermal limit violations in the preceding three year time period using the more restrictive calculated limits. 

Corrective actions have been put into place to ensure discrepancies of this type do not occur in the future. PNPS has confirmed that the reload analysis for Cycle 21 does not credit the high level feedwater pump trip and that the fuel vendor has taken no deviations from PNPS provided inputs in performance of the transient analyses. Accordingly, going forward, beginning with Cycle 21, the statements in the October 3, 1994, letter will be complete and accurate as originally intended. 

Please contact me at (508) 830-8323 if you have any questions.

Limerick: Information On Testing US Reactor Vessels and Belgium Cracks

It is basically the blind leading the blind with my understanding this???

Big questions:

1) What does this mean and is it going on in the USA?  

"In carrying out tests related to theme 2 during the spring of 2014, a fracture toughness test revealed unexpected results, which suggested that the mechanical properties of the material were more strongly influenced by radiation than experts had expected."

Alliance for a Clean Environment response from NRC

May 5, 2015

Dr. Lewis Cuthbert

President

Alliance for a Clean Environment

1189 Foxview Road

Pottstown, PA 19465

Dear Dr. Cuthbert:

May 5, 2015

On behalf of the U.S. Nuclear Regulatory Commission (NRC), I am responding to your e-mail dated March 16, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML 15076A480), expressing concerns primarily about cracking, due to embrittlement, of the reactor pressure vessels at Limerick Generating Station, Units 1 and 2. I have included answers to your specific concerns in the enclosure to this letter. Thank you for contacting the NRC with your concerns.

'NRC Response to Concerns in March 16, 2015, E-Mail From the Alliance for a Clean Environment Regarding Limerick Generating Station, Units 1 and 2'

Background

This enclosure provides the U.S. Nuclear Regulatory Commission's (NRC's) response to concerns regarding Limerick Generating Station, Units 1 and 2 (Limerick), as discussed in the March 16, 2015, e-mail from the Alliance for a Clean Environment (ACE) (Agencywide Documents Access and Management System (ADAMS) Accession No. ML 15076A480). ACE previously raised some of the same concerns in an e-mail dated November 9, 2014(ADAMS Accession No. ML 14321A054). The NRC staff provided a response in an e-mail dated December 8, 2014 (ADAMS Accession No. ML 14345A078).

Destructive Testing

ACE raised concerns regarding embrittlement of the Limerick reactors and asked if destructive testing of the reactors had been performed.

When a nuclear plant is operated, neutron radiation from the reactor core causes embrittlement of the reactor pressure vessel (RPV). Embrittlement refers to a decrease in the fracture toughness of RPV materials and affects the vessel materials in the section closest to the reactor fuel, referred to as the vessel's "beltline."

Section 50.60 of Title 10 of the Code of Federal Regulations (10 CFR), "Acceptance criteria for fracture prevention measures for lightwater nuclear power reactors for normal operation," requires compliance with the

Basically this is saying a plant is licensed with a vessel with these kinds of metallurgical properties based on 1960s technology and knowledge. No other inspections is necessary throughout the life of the plant.  

fracture toughness and material surveillance program requirements set forth in Appendices G and H to 1 O CFR Part 50. Compliance with the requirements of this rule, and the associated appendices, provides assurance regarding the structural integrity of the reactor coolant pressure boundary (RCPB) and, specifically, the RPV.

Appendix H to 10 CFR Part 50, "Reactor Vessel Material Surveillance Program Requirements," requires nuclear power plant licensees to implement RPV surveillance programs to monitor changes in the fracture toughness properties of ferritic materials in the RPV beltline region which result from exposure of these materials to

For a host of reasons, I don't think the coupon specimen surveillance is representative of the properties of the vessel. Basically a crack in the reactor vessel bypasses all the safety designs of the plant and a accident could be so severe, we need actual ultrasonic testing of the vessel. A stand in coupon testing is no longer a guarantor of safety. 

neutron irradiation. The RPV surveillance programs require destructive testing of material test specimens that are representative for the materials in the reactor. Two specific alternatives are provided for the design of a facility's RPV surveillance program to address the requirements of Appendix H to 10 CFR Part 50.

The first alternative, provided in Appendix H to 1 O CFR Part 50, is the implementation of a plant specific RPV surveillance program consistent with the requirements of American Society for Testing of Materials (ASTM) E 185, "Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels."

The second alternative, provided in Appendix H to 10 CFR Part 50, is the implementation of an Integrated

You get it, always a stand in type testing, never inspection the real deal. Basically it is too expensive and disrupting the capacity factor.  

Surveillance Program (ISP). When a licensee uses an ISP, representative materials chosen for surveillance of a reactor are irradiated in one or more other reactors that have similar design and operating features.

As discussed in the NRC staff's safety evaluation for a Limerick amendment dated November 4, 2003 (ADAMS Accession No. ML032310540), Limerick, Units 1 and 2, have implemented the Boiling Water Reactor Vessel and Internals Project (BWRVIP) ISP as the basis for demonstrating compliance with the requirements of Appendix H to 1 O CFR Part 50.

To comply with Appendix H to 10 CFR Part 50, the entire fleet of operating U.S. reactors, including the Limerick RPVs, contain material specimens, representative of the materials in RPV beltline region, in surveillance capsules. These surveillance capsules are removed for

So they got specimens designed to be remove for testing from the vessel, but are never required to be tested. 

destructive testing of the material specimens as necessary. None of the surveillance capsules in the Limerick RPVs have been removed to date. In addition, as discussed in a Limerick license amendment dated April 8, 2011 (ADAMS Accession No. ML 110691095), based on the BWRVIP ISP, Limerick is not scheduled to remove any surveillance capsules in the future. 

Instead, the limiting weld and plate materials for the Limerick RPVs are monitored through representative material specimens that are exposed to irradiation in other boiling water reactors, as part of the BWRVIP ISP. The BWRVIP ISP was found acceptable by the NRC staff to satisfy the requirements of Appendix H to 10 CFR Part 50, during the period of extended operation for Limerick, as discussed in the Section 3.0.3.1.11 of NUREG-2171, "Safety Evaluation Report Related to the License Renewal of Limerick Generating Station, Units 1 and 2" (ADAMS Accession No. ML 14276A156).

In summary, destructive testing has not been performed on the material specimens in the Limerick RPV surveillance capsules. Destructive testing has been and will continue

Ultrasonic like I want is not destructive and the destructive testing of drilled out specimens  I want is from permanently  shutdown plants.  Further I want ultrasonic testing of the permanently shutdown vessels...if no defects are discovered then no further inspection are needed.  

to be performed, for material specimens representative of the materials in the Limerick RPV, to meet the requirements in Appendix H to 10 CFR Part 50, as part of the BWRVIP ISP.

Material Fatigue Testing

ACE requested that the NRC "require independent 'material fatigue' testing of both Limerick Nuclear Plant reactors, with the results of testing immediately reported to the public."

All U.S. nuclear RPVs are designed and fabricated for operational cyclic stresses caused by all postulated loadings, including startup, shutdown, and scram events. Fatigue is explicitly evaluated as a part of the design

Based on 1960s technology and knowledge!!! 

process. Once the RPV is designed and fabricated and placed into service, licensees are required to track operational events, such as startups and shutdowns, to ensure they remain within their design bases with respect to fatigue. The NRC staff found that Limerick's fatigue program satisfied these requirements for the extended period of operation, as discussed in Section 4.3 of NUREG-2171, "Safety Evaluation Report Related to the License Renewal of Limerick Generating Station, Units 1 and 2" (ADAMS Accession No. ML 14276A 156). As a result of satisfying these requirements, there is no demonstrated need for material fatigue testing at Limerick.

The NRC's regulations in 10 CFR 2.206 describe the

At least I got this right... 

petition process, which is the primary mechanism for the public to request enforcement-related action by the NRC in a public process. This process permits anyone to petition the NRC to take enforcement-related action associated with NRC licensees or licensed activities. Depending on the results of its evaluation, NRC could-modify, suspend or revoke an NRC-issued license or take any other appropriate enforcement related action to resolve a problem.

Although ACE's e-mail dated March 16, 2015, did not specifically cite the 10 CFR 2.206 process, it did request enforcement-related action (i.e., ACE's request to require material fatigue testing at Limerick). The NRC staff has previously offered the use of the petition process to address concerns where enforcement-related action was requested by ACE (e.g., NRC e-mail dated April 23, 2014 (ADAMS Accession No. ML 14129A184)). However, ACE has previously rejected use of the NRC's petition process to address its concerns (e.g., letter dated July 25, 2014 (ADAMS Accession No. ML 14216A339)). Nevertheless, the NRC staff considers the 10 CFR 2.206 petition process to be the appropriate process to address requested enforcement-related action. The NRC's petition process is available if ACE disagrees with the NRC's findings and has information the NRC did not consider in making its findings.

Belgium Reactor Operating Experience

ACE cited issues with cracking that had been reported in two reactor vessels in Belgium.

The NRC staff is well aware of this issue. Evaluations in Belgium and the U.S. demonstrated that because these many flaws are oriented nearly parallel to the direction of stress in the reactor vessel shell, they do not pose a significant safety concern. Additionally, it should be

Suggest isn't proof it is safe. Again this is a inference a vessel is safe, not acceptable proof it is safe. 

It is generially a new kind of corrosion/ hydrogen process...hydrogen collecting deep into the vessel leading to crack and flaws.

As far as I can see, nobody has taken a sample and cut into metal, thus nobody really what is going on.  

noted that information available from Belgium suggests that the flaws occurred as part of the initial fabrication process (i.e., flaws are not service-induced). As such, there is no indication that the flaws in the Belgium reactors are in any way related to fatigue damage.

Notes:

*** At least one reactor in Switzerland, another in Belgium and two in Spain have components produced by the same Dutch firm, Rotterdam Drydock Company, which has gone bankrupt since producing the equipment. The U.S. Nuclear Regulatory Commission said Friday it has been informed that 10 American reactors may have used the component in question, but it hasn't yetverified that information with U.S. nuclear operators.

***Doel 3/Tihange 2: new update

After a large number of flaw indications was discovered in the walls of the reactor pressure vessels (RPVs) of Doel 3 and Tihange 2 during a scheduled maintenance in the summer of 2012, the Belgian nuclear safety authorities (FANC and Bel V) decided that Electrabel had to submit a Safety Case to justify the restart of both reactors. Electrabel had to demonstrate specifically and convincingly in its Safety Case that the flaw indications in the walls of the RPVs do not compromise its structural integrity. 

After an analysis of the safety cases of both reactors, the FANC and Bel V decided on May 17, 2013 that Doel 3 and Tihange 2 could be restarted. Linked to this agreement, however, was the condition that Electrabel had to perform a series of medium-term actions to consolidate the hypotheses of its Safety Case. These actions were divided into three major themes:

1. The ultrasonic inspection technique of the RPVs: detection and measurement of hydrogen-induced flaw indications
2. Material properties of steel containing hydrogen flakes
3. Structural integrity of a rpv containing hydrogen flakes

The results of the actions on issues 1 and 2 provide the input for theme 3. 

"In carrying out tests related to theme 2 during the spring of 2014, a fracture toughness test revealed unexpected results, which suggested that the mechanical properties of the material were more strongly influenced by radiation than experts had expected." As a precaution both reactors were immediately shut down again.

Electrabel launched a test campaign to find an explanation for the unexpected test results.
At the same time, the licensee continued the execution of the medium termed-action plan. In the mean, this has led to the following results:

More accurate information about the flaw indications 

In February 2015, Electrabel completed the actions related to the theme of the ultrasonic inspection technique. 

This technique was originally designed for the control of the welding and the cladding of the RPV, but it also proved to be able to detect flaw indications in the wall of the RPV. Electrabel had to qualify the technique, i.e. prove that all hydrogen-induced flaw indications can be found and can be measured correctly using the ultrasonic inspection. By doing so, Electrabel found that the inspection procedure had to be slightly modified and that the detection threshold of the probes had to be lowered to ensure the proper detection of all flaw indications.
In 2014, a further inspection was carried out based on the improved procedure and the modified settings of the machine, resulting in the detection of a greater number of flaw indications than was measured in 2012 and 2013. This means that Electrabel now has to take into account 13 047 flaw indications for Doel 3 and 3149 flaw indications for Tihange 2 in its calculations. These additional flaw indications are similar to those which were previously considered and are located in the same area of the RPV. 

New sequence of material testing 

At the same time, Electrabel also continues its research on the material properties of the RPV and the unexpected results of the previous fracture toughness test. 

Currently a 4th irradiation campaign is being executed in the research reactor BR2 of the SCK, where, next to hydrogen-flaked samples of the French VB395 test material, other hydrogen-flaked samples of another test material of German origin are also being irradiated. The results of this irradiation campaign and of the subsequent material tests are expected by April 2015. 

New meeting of the international review board 

Electrabel provides the FANC and Bel V with results of ongoing tests and analyses on a regular basis. The Belgian security authorities need time to look into this new information and will continue their analysis during the first months of 2015. Therefore, they call in the help of international experts who are specialized in damage mechanisms caused by radiation and in mechanical resistance tests. This international expert panel (International Review Board) met for the first time in Brussels at the start of November 2014. The main conclusion of this meeting was that the methodology used by Electrabel was not yet sufficiently developed to make a well-grounded judgment. The international experts have formulated some suggestions for further actions and studies. Based on these suggestions and on the documents already analyzed, the Belgian security authorities have passed a series of additional demands and suggestions to Electrabel, so that the licensee can adjust its methodology and validate the underlying hypotheses of its arguments. 

In April 2015, the FANC will organize a new meeting of the international panel of experts to obtain their advice on the results of the new material tests and on the new data provided by Electrabel.

***Good Back Ground info: Report Activities in WENRA countries following the Recommendation regarding flaw indications found in Belgian reactors

Strange Sentence in New Brunswick Nuclear Plant Inspection Report???

I was looking for Diesel Generator problem, but found this? It is in a operability determination. 

Some kind of Ariva fuel problem going to impact Brunswick in 2015? How widespread is it in the USA?  

April 30, 2015: BRUNSWICK STEEM - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2015001 AND05000324/2015001 

"Units 1 and 2, Atrium-10 fuel assembly load chain failure event at Chinshan – impact for operating cycle, March 30, 2015"

Chinshan nuclear plant is in Taiwan???