05000440/LER-2013-001, Regarding Loss of Feedwater Results in Automatic Reactor Protection System Actuation
| ML13085A078 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 03/21/2013 |
| From: | Kaminskas V FirstEnergy Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| L-13-073 LER 13-001-00 | |
| Download: ML13085A078 (6) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(i) 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded 10 CFR 50.73(a)(2)(viii)(A) 10 CFR 50.73(a)(2)(ii)(B), Unanalyzed Condition 10 CFR 50.73(a)(2)(viii)(B) 10 CFR 50.73(a)(2)(iii) 10 CFR 50.73(a)(2)(ix)(A) 10 CFR 50.73(a)(2)(x) 10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications |
| 4402013001R00 - NRC Website | |
text
FENOCTM FirstEneigy Nuclear Operating Company Perry Nuclear Power Plant P.O. Box 97 10 Center Road Perry, Ohio 44081 Vito A. Kaminskas Vice President 440-280-5382 Fax: 440-280-8029 March 21, 2013 L-13-073 10 CFR 50.73(a)(2)(iv)(A)
ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001
SUBJECT:
Perry Nuclear Power Plant Docket No. 50-440, License No. NPF-58 Licensee Event Report Submittal Enclosed is Licensee Event Report (LER) 2013-001, "Loss of Feedwater Results in Automatic Reactor Protection System Actuation." There are no regulatory commitments contained in this submittal.
If there are any questions or if additional information is required, please contact Mr. Thomas Veitch, Manager - Regulatory Compliance, at (440) 280-5188.
Sincerely, (
Vito A. Kaminskas
Enclosure:
LER 2013-001 cc:
NRC Project Manager NRC Resident Inspector NRC Region III
NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104 EXPIRES 10/31/2013 (10-2010)
, the NRC may digits/characters for each block) not conduct or sponsor, and a person is not required to respond to, the information collection.
- 3. PAGE Perry Nuclear Power Plant, Unit 1 05000-440 1 OF5
- 4. TITLE Loss of Feedwater Results in Automatic Reactor Protection System Actuation
- 5. EVENT DATE
- 6. LER NUMBER f
- 7. REPORT DATE
- 8. OTHER FACILITIES INVOLVED SEQUEN~TIAL REV FACILITY NAME DOCKET NUMBER MONTH DAY YEAR YER UBER NO MONTH DAY YEAR I~
Z Z IFACILITY NAME DOCKET NUMBER 01 22 2013 2013
- - 001 00 03 21 2013
- 9. OPERATING MODE
- 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check all that apply)
[] 20.2201(b)
LI 20.2203(a)(3)(i)
[] 50.73(a)(2)(i)(C)
[] 50.73(a)(2)(vii)
El 20.2201(d)
[] 20.2203(a)(3)(ii)
[-
50.73(a)(2)(ii)(A)
EI 50.73(a)(2)(viii)(A)
[] 20.2203(a)(1)
El 20.2203(a)(4)
El 50.73(a)(2)(ii)(B)
LI 50.73(a)(2)(viii)(B)
LI 20.2203(a)(2)(i)
[] 50.36(c)(1)(i)(A)
[E 50.73(a)(2)(iii)
El 50.73(a)(2)(ix)(A)
- 10. POWER LEVEL
[' 20.2203(a)(2)(ii)
[I 50.36(c)(1)(ii)(A)
Z 50.73(a)(2)(iv)(A)
El 50.73(a)(2)(x)
[] 20.2203(a)(2)(iii)
El 50.36(c)(2)
[] 50.73(a)(2)(v)(A)
El 73.71 (a)(4) 99.8 E] 20.2203(a)(2)(iv)
El 50.46(a)(3)(ii)
El 50.73(a)(2)(v)(B)
El 73.71(a)(5)
El 20.2203(a)(2)(v)
E] 50.73(a)(2)(i)(A)
El 50.73(a)(2)(v)(C)
Z OTHER Specify in Abstract below S20.2203(a)(2)(vi)
E 50.73(a)(2)(i)(B) lj 50.73(a)(2)(v)(D) or in
CAUSE OF EVENT
The RPS scram was caused by an electrical transient in the balance-of-plant (BOP) 120 volt AC Uninterruptable Power Supply (UPS) system [EJ]. The transient was caused by a degraded static transfer switch component [ASU] coincident with a failed DC to AC inverter [INVT]. The static transfer switch did not seamlessly transfer the loads to the alternate source. The inverter was found on the alternate source with the fail light illuminated and its protective fuse actuated. The control logic for the Digital Feedwater Control system (DFWCS) is one of the electrical loads serviced by the UPS. Disruption of the DFWCS logic due to the electrical transient affected the feedwater system by driving the RFP controllers to minimum flow with no start signal being sent to the MFP per design. As a result, feedwater flow was lost to the RPV and the RPS actuated, as designed, when RPV Level 3 was reached.
No failed internal components were identified through initial troubleshooting of the BOP inverter and static transfer switch. A root cause evaluation found that there was inadequate preventive maintenance (PM) performed on the static transfer switch, which was designated as a single point vulnerability (SPV) critical component. The sensing and transfer card on the static transfer switch had degraded and not been designated for replacement under the PM program. The static transfer switch attempted to transfer loads to the alternate source. The resultant cycling of loads on the inverter affected performance of the silicon controlled rectifiers (SCRs), which convert DC to AC current, and ultimately caused the transient.
A contributing cause was inadequate reliability improvements for the inverter and static transfer switch. These components are located near an exterior roll-up steel door. Operation of the inverter at low ambient temperatures or at sharp changes in temperature could cause the SCRs to misfire resulting in a momentary short circuit condition. High winds and cold outside temperatures existed at the time of the event.
Another contributing cause was that opportunities were missed in 2007-2009 to objectively evaluate and resolve reliability issues with the inverter and static switch and PM requirements through use of the corrective action program.
EVENT ANALYSIS
The UPS provides a highly reliable source of 120 VAC electrical power to specific plant loads.
Power to the BOP loads is supplied by a 125V battery and is routed through a distribution bus, an inverter to convert DC to AC power, and a static transfer switch. If the inverter output voltage drops too low, the static transfer switch will transfer to the alternate source. The UPS is not controlled by Technical Specifications and is not essential to safe shutdown functions.
There were no complications during the shutdown as all control rods fully inserted and pressure was maintained by normal means. The RPS functioned as designed.
The scram event, including plant response, is bounded by the Loss of Feedwater Flow transient evaluated in the Updated Safety Analysis Report (USAR) Chapter 15, Accident Analysis, Section 15.2.7. As a direct result of the scram, no plant parameters challenged the transients as described in the USAR. This transient is categorized as an incident of moderate frequency.
A probabilistic risk assessment (PRA) was performed for this event. The PRA assessment calculated a change in core damage frequency (delta CDF) in this case to be 9.OE-08/yr and a delta large early release frequency (LERF) of 4.6E-08/yr. The delta CDF and delta LERF values are well below the acceptable thresholds of 1.0E-06/yr and 1.0E-07/yr respectively as discussed in Regulatory Guide 1.174. Plant configurations with changes in CDF of less than 1.OE-06 and LERF of less than 1.OE-07 are not considered to be significant risk events. Based on the PRA results, the safety significance of this event is considered to be small.
ORM section 7.6.2.1 requires a Special Report be submitted following an ECCS actuation and injection into the reactor coolant system. The report shall include a description of the circumstances of the actuation and the total accumulated actuation cycles to date. The current value of the usage factor for each affected safety injection nozzle shall be provided when its value exceeds 0.70. Following the scram, the HPCS system actuated once for level control and injected into the RPV for approximately three minutes. This injection brings the total number of HPCS injections to 43 over the life of the plant. The current design Cumulative Fatigue Usage Factor (CFUF) for the limiting location of the HPCS nozzle is 0.567. The number of design HPCS injections is 60. The number of operating HPCS injections is bounded by the design allowance.
The current design CFUF value is less than ORM Special Report Limit (0.70).
CORRECTIVE ACTIONS
Initial troubleshooting and problem solving activities were completed; no failed components were found in the inverter or static transfer switch. The Gate Driver and Logic Power Supply circuit cards in the static transfer switch were replaced. A temporary enclosure (i.e., curtain) was erected around the inverter and static transfer switch to protect them from affects of cold temperatures.
An Operational Decision Making Issue (ODMI) evaluation was prepared and approved to operate in this alignment under administrative controls through the next refueling outage. The power plant was then restarted with BOP 120 VAC electrical loads aligned to the alternate power supply. The circuit was classified as a Protected Train which prevented further troubleshooting efforts. The following repairs are planned for the next refueling outage to restore the inverter and static transfer switch to a state of continued reliability:
" Replace the Sensing and Transfer circuit card in the static switch and complete troubleshooting to identify and replace any other failed or degraded components.
" Replace the circuit cards within the BOP inverter (i.e., modulation index, synchronizer, reference oscillator, logic power supply, and gate driver) since they are outside the PM program recommended replacement frequency.
Other corrective actions planned include:
Revise the preventive maintenance plan to replace the Static Switch Sensing and Transfer card in accordance with the recommended PM program frequency (i.e., 10 years).
" Complete the review of critical systems with single point vulnerabilities. Create functional locations for sub-components and develop proper PM program strategies and mitigation strategies. 26 plant systems were previously reviewed prior to this failure, 23 remain.
Create a PM task to replace the BOP inverter cards in accordance with the recommended PM program frequency (i.e., 12 years).
Evaluate and implement a solution to the static transfer switch SPV to resolve the temperature sensitivity issue and harden the design such that a failure does not cause a loss of feedwater.
PREVIOUS SIMILAR EVENTS
A review of LERs and the corrective action database for the past three years did not identify any previous similar events or condition reports relevant to the inverter/static transfer switch failure mechanism. Corrective actions for the following RPS actuations were reviewed. None of the actions would have been reasonably expected to have prevented the event documented in this LER.
LER 2012-001, Manual Reactor Protection System Actuation due to Automatic Turbine Generator Runback LER 2010-003, Loss of Control Rod Drive Header Pressure Results in Manual RPS Actuation LER 2009-001, MSR High Level Signal Causes Turbine Trip and Reactor Protection System Actuation
COMMITMENTS
There are no regulatory commitments contained in this report. Actions described in this document represent intended or planned actions, are described for the NRC's information, and are not regulatory commitments.