ML20148C644
| ML20148C644 | |
| Person / Time | |
|---|---|
| Site: | Maine Yankee |
| Issue date: | 06/30/1996 |
| From: | OAK RIDGE NATIONAL LABORATORY |
| To: | NRC |
| Shared Package | |
| ML20148C622 | List: |
| References | |
| ORNL-NOAC-307, NUDOCS 9705270191 | |
| Download: ML20148C644 (61) | |
Text
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l ENCLOSURE 2
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- l ORNUNOAC-307 i
j REVIEW OF THE OPERATING EXPERIENCE i
FOR MAINE YANKEE i
FROM JANUARY 1993-MARCH 1996 i
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JUNE 1996 i
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DISCLAIMER This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, i
completeness, or usefulness of any information, apparatus, product or process disclosed, or represents that its use would not infringe privately owned rights.
References herein to any specific commercial product, process, or service, does not necessarily constitute or imply its endorsement, recommendation or favoring by the United States Government or any agency thereof. The views and opinions expressed herein do not necessarily state or reflect those of the United States Government or any ag:ncy thereof.
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Table of Contents List of Tables...........
ii List or lagur es.............................................
ii Executive S um mary
............................................................ iii 1.0 I NTR O D U CTI O N............................................................. I l
2.0 ANALYSIS OF LERS AS A FUNCTION OF REPORTABILITY CATEGORIES 5
2.1 10 CFR 50.73(a)(2)(i) - Shutdown or Technical Specification Violation............. 6 2.2 10 CFR 50.73(a)(2)(ii) - Unanalyzed Conditions............................. 10 2.3 10 CFR 50.73(a)(2)(iv) - ESF Actuations................................. 13 3.0 ANALYSIS OF PERSONNEL ER RORS........................................... 16 3.1 Intrinsic Human Errors............................................. 16 3.1.1 Maintenance /R epair........................................... 16 3.1.2 Installation.............
................. 18 3.2 Task Description inadequacies.....,y.................................... 19 3.2.1 Ope r a t i ons.................................................. 19 4.0 ANALYSIS OF COMPONENT FAILURES........................................ 22
- 4.1 Valves............................................................23 42 I & C/S wi t ch es...................................................... 24 4.3 Circuit Breakers / Fuses............................................... 25 4.4 H ea t Exchange rs.................................................... 26 5.0 ANALYSIS OF TRAIN FAILURES AND SYSTEM OCCURRENCES...,.............. 28 5.1 Residual Heat Rem ova!.............................................. 29 5.2 Cont ai n m e nt S pray.................................................. 30 5.3 Fire Prot ection..................................................... 31 5.4 Com pone nt Cooling Water............................................ 32 6.0 ANALYSIS OF NRC PERFORMANCE INDICATOR DATA........................... 35 6.1 Analpis.......................................................... 35 6.2 Recent Significant Events.............................................. 36 APPENDIX A: LISTING OF MAINE YANKEE LERS BY CATEGORY..................... A 1 APPENDIX B: ABSTRACTS FOR MAINE YANKEE LERS............................... B.1 i
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Executive Summary The Nuclear Operations Analysis Center (NOAC) was requested by the NRC's Office for Analysis and Evaluation of Operational Data (AEOD) to review the operating experience for Maine Yankee from January i
1993 through March 1996. This review is intended to assist NRC staff in preparing for an Independent Safety J
Assessment of Maine Yankee. To perform this current review, the 62 Licensee Event Reports (LERs) from Maine Yankee that were submitted during the assessment period were examined. The Sequence Coding and Search System (SCSS) database was used to identify LER categories for further analysis. Based on a review of l
the SCSS searches the following areas were examined in detail:
1 Licensee Event Reports (LERs) involving the following reportability criteria 3
10 CFR 50.73(a)(2)(i) - Shutdown or Technical Specification Violation (Section 2.1)
+
10 CFR 50.73(a)(2)(ii) Unanalyzed Conditions (Section 2.2)
Personnel errors involving intrinsic human errors and task description inadequacies.
j (Sections 3.1 and 3.2).
Component failures involving valves, I&C switches, circuit breakers, and heat exchangers (Sections 4.1 through 4.4).
Train failures involving the residual heat removal, containment spray, fire protection, and component cooling water systems (Sections 5.1 through 5.4).
In addition, the NRC Performance Indicator (PI) data was analyzed to determine areas for further examination.
Outage rciated information was compiled as a result of this assessment (Section 6.1). Maine Yankee had no events designated as a Significant Event by the NRC.
No Augmented Inspection Teams (AIT) were sent to the Maine Yankee site by the NRC during the review period.
The 1993,1994, and 1995 (draft) Accident Sequence Precursor events were reviewed and no events for Maine Yankee were identified.
The issues noted were.
The average number of LERs reported by Maine Yankee was approximately 35% higher than the peer e
group average. Maine Yankee reported higher numbers of shutdowns or Technical Specification (TS) violations and unanalyzed conditions than did other plants in its peer group. An example of an event reporting a TS violation is:
l On November 4,1993, with the plant operating at 100% power, operators were conducting monthly surveillance Control Element Assembly (CEA) exercising following a refueling outage.
At the beginning of the surveillance, operators were aware that an intermittent malfunction had l
rendered the reed switch CEA position deviation alarm inoperable. During the smveillance it was discovered that the CEA pulse counting deviation alarm was also inoperable. Whenever the reactor is critical, TS require that if the CEA deviation alarms from both the computer i
pulse counting system and the reed switch indication system are not available, individual CEA positions shall be logged and mhahgnment checked every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The reactor was taken critical almost a month earlier. Investigation determined that the rod position sensing system
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(RPSS) cards were removed for troubleshooting during the refueling outage on 10/01/93, thus disabling the required pulse counting system alarm functions. Since both pulse and reed CEA 1
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Deficiencies in procedures used by operators was another area where Maine Yankee reported more e
errors than the peer group. An example of an event with operations procedures deficiencies is:
On May 18,1994, the reactor tripped from 100% power on loss of load due to a main turbine trip caused by a turbine-driven feedwater pump (TDFP) trip. The TDFP tripped on overspeed when high pressure (HP) steam was manually aligned to the TDFP. Earlier, an air leak on a 345 KV switchyard breaker required decreasing power to 70% to allow breaker isolation.
Reactor power was maintained at 100% while the main turb!nc load ms being reduced. At 80%, the main turbine enraction steam did not have sufficiem pressure to run the TDFP and therefore HP steam had to be aligned. The control room recognized that the HP governor valve was cycling and dispatched an operator to open the HP isolation valve. Since the HP governor valve already had a high open demand signal, the pump tripped on overspeed. The root cause of the plant trip was inadequate procedural guidance. (309/94-008)
Overall, there appeared to be no discernible, adverse trends nor safety-significant operational problems based j
on this review. Two areas that may warrant further investigation as just highlighted include (1) LERs reporting i
Technical Specifications violations and (2) deficiencies in procedures used by the operators.
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1.0 INTRODUCTION
& Nuclear Operations Analysis Center (NOAC) was requested by the NRC's Office for Analysis and Evaluation of Operational Data (AEOD) to review the operating experience for Maine Yankee from January 1993 through March 1996. This review is intended to assist NRC staffin preparing for a Independent Safety Assessment of Maine Yankee.
This review focused on selected areas and does not provide overall fmdings regarding plant operations. Any findings or observations are relevant only to the specific areas analyzed.
Tables 1.1 through 5.2 summarize the initial data screening that was performed. Based on a review of these data, the following areas were selected for further analysis:
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Licensee Event Reports (LERs) involving the following reportability criteria 10 CFR 50.73(a)(2)(i) - Shutdown or Technical Specification Violation (Section 2.1) 10 CFR 50.73(a)(2)(ii) - Unanalyzed Conditions (Section 2.2)
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Personnel errors involving intrinsic human errors and task description inadequacies.
(Sections 3.1 and 3.2).
j Component failures involving valves, I&C switches, circuit breakers, and heat exchangers l
(Sections 4.1 through 4.4).
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Train failures involving the residual heat removal, containment spray, fire protection, anri component cooling water systems (Sections 5.1 through 5.4).
In addition, the NRC Performance Indicator (PI) data were analyzed to determine possible areas for further examination. Outage related information was also compiled as a part of this assessment (Section 6.1).
Maine Yankee had no events that were designated as a Significant Event by the NRC. (Section 6.2)
No Augmented Inspection Teams (AIT) have been sent to the Maine Yankee site by the NRC since 1993.
The 1993,1994, and 1995 (Draft) Accident Sequence Precursor events were reviewed and no events for Maine Yankee were reported.
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& areas for review were generally selected based on two criteria: (1) a high number of events occurred at Maine Yankee, and (2) the number of events at Maine Yankee was higher than the average number of events at the rest of the peer group plants. The first criterion is intended to ensure that there are a suffx:icat number of events present from which to draw general conclusions. The sera =A criterion huhcates areas where the performance of Maine Yankee differs from that of the other plants in the peer group.
The operating performance of Maine Yankee was compared to other plants similar in design. Table 1.1 describes all of the plants in the sarne peer group of Combustion Engmeeting Plants (w/o a Core Protection Calculator.) All peer group data presented throughout this report exclude the contribution of Maine Yankee to the peer group averages.
The data in the tables were derived from LER information contained in the Sequence Coding and Search System (SCSS). The indicated number of personnel errors, component failures, system occurrences, etc., presented in the tables reflect the actual numbers of errors or failures as encoded in SCSS, not a count of LERs involving those failures. Note that a single LER may involve multiple errors or failures, resulting in more errors and failures than LERs.
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l Table 1.1 Cornbustion Engineering Plants (w/o a Core Protection Calculator)
Plant Name Docket Initial Cnticality Date Commenial Dcctrical Rating Operation Date (MWe-net)
Cohert Oiffs 1 317 10/74 Sg5 825 i
Cahert Oiffs 2 318 1106 4/77 825 i
Fort Colhoua 285 803 9#3 478
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, l[fJB2M Millstone 2 336 10B5 12/75 8 75 Palisades 255 5/71 12/71 780 St. Lucic 1 335 4/76 12/76 839 hl l
St. Lucie 2 389 6/83 8/83 839 10 Maine Yankee LERs l EZ21OperatanalLERs C""] Srddown LERs
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%3 94 El E2 96-3 54 E1 Figure 1.1 Maine Yankee LERs by Quarter with Operational Status 3
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2.0 ANALYSIS OF LERS AS A FUNCTION OF REPORTABILITY CATEGORIES c
Table 2.1 compares the percentage of LERs in various reportability categories for events occurring at Mame Yankee to the average for its peer group. This table indicates that Maine Yankee reported a slightly higher percentage of LERs compared to its peer group for Shutdowns or TechnicalSpecification Violation.This category represents the highest percentage of events reported by Maine Yankee. ESF Actuations were reported as the second lowest percentage of events at the station. (This category also includes events reporting RPS actuations.)
Although LERs for Unanalyzed Conditions were the second highest percentage for Maine Yankee, they were the same percentage as the peer group. Although Maine Yankee reported a higher percentage of Other LERs, only one of these was not voluntary, and characterizing these would yield little useful information. The following sections provide short summaries of events reporting (1) Shutdown or Technical Specification (TS) violations, (2) Unanalyzed Conditions, and (3) ESF actuations. Although percentage for the first two categories is about the same as the peer group, these are characterized due to high percentage of LERs at Maine Yankee reported in the category. ESF actuations are listed due to the significance of the category.
Table 2.1 Comparison of Reportability Categories for Maine Yankee and Peer Group Plants Number of Percentage of Percentage
,3 Reportability Category Maine Yankee Maine Yankee for Peer LERs*
LERs Group LERs Shutdown or Technical Specification 27 44 40 l
Violation -10 CFR 50.73(a)(2)(1)
Unanalyzed Condition - 10 CFM 14 23 23 50.73(a)(2)(li)
Other: Voluntary Report, Spedal Report, 12
-19 5
i Past 21 Report, etc.
Event That Could Have Prevented
-6 10 14 Fulfillment of a Safety Function - 10 CFR 50.73(a)(2)(v)
ESF Actuation - 10 CFR 50.73(a)(2)(iv) 4 6
24 Common Mode / Single Failures - 10 CFR 1
2 3
50.73(a)(2)(vii)
- IE.Rs can have more than one reportat>ility category.
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i immediate alarm notification if a CEA were to become misaligned. This was determined to be of minimal safety consequence since numerous other non-alarm indicators were available to alert the operators to any misalignment. The apparent root cause was determined to be' human error in failure to comply with existing administrative controls for removing RPSS cards.
l (309/93-021)
On May 17,1994, during an audit of the Emergency Core Cooling System (ECCS) locked valve program, the licensee found a one-inch globe valve on an ECCS subsystem was not locked in i
its correct ECCS position. Another valve serving the same function and controlled by a class A procedure was closed but not locked. This valve was subsequently locked. The function of 1
both valves is to isolate Secondary Component Cooling (SCC) water to the chemical addition tank. TSs requires manual ECCS valves (and subsystem valves) to be aligned and locked in the position required for safeguards operation. (309/94-007) j On November 1,1995, while in refueling outage, a control room operator (CRO) commenced a daily radiation monitoring system (RMS) test. After completing the test, the CRO left the i
containment purge valve mode selection switches in the 'on-line' position, rather than restoring them to the " refueling" position. The day shift CRO found the switches mispositioned during i
routine checks eight and one-half hours later, and after fuel movement had occurred. The I
safety significance of this event is that the valves would not have closed as required upon a high j
i radiation signal from a fuel handling incident. The time period of 30 minutes allowed by TSs for the switch to be in the "on.line" position for testing was exceeded. (309/95-016)
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On February 1,1996, while at 90% power, the Shift Operating Supervisor (SOS) restored the j
"out of service" Secondary Component Cooling (SCC) heat exchanger to operation. He did not recognize that one vent valve was an ECCS valve, required to be closed and locked per TSs.
Two procedures were referenced for final position, but one procedure was incorrect and had not been updated and the other was misread, which resulted in the valve being positioned to one turn open and locked. On February 5,1996, a Non-Licensed Operator (NPO) was performing a surveillance on ECCS alignment and found the vent valve was not positioned correctly per the procedure. The NPO immediately informed the SOS, and after procedure review, was dispatched to close and lock the valve. (309/96-002)
Ten LERs reported events associated with procedure deficiencies or weaknesses in administrative controls:
On November 16,1992, while at 100% power, a review of an experience report concerning temporary disabling of Emergency Core Cooling System (ECCS) subsystems during valve stroke testing found that the report was potentially applicable to Maine Yankee. Operations personnel later concluded that for.a brief period, during stroke testing of either normally open ECCS pump minimum-flow recirculation valves, both trains of ECCS low Pressure Safety injection (LPSI) and Containment Spray (CS) subsystems must be considered inoperable. These valves had been tested on a monthly basis during ECCS valve tests. %e apparent root cause of this event was failure of the original TSs to allow for surveillance testing of the m*mimum-flow recirculation valves, even though the survedlance test is required. There were no exceptions in the LCO for ECCS that permitted this testing. NRC interpretations concluded that this condition is reportable under 10CFR50.73. Identical occurrences were documented in LERs 309/93-009 and 309/93-014. Similar occurrences for the Spray Building Exhaust Ventilation 1
were documented in LERs 309/93-010 and 309/94-009. This ventilation system is needed to be j
operable for LPSI and CS to be considered operable. (309/93-001) 7 i
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The inner hatch O ring was cleaned, inspected and lubricated, and the door placed back in service. The time required to open and close the outer door was less than five minutes, so no shutdown was required. After the outer hatch was secured, the TS was exited. Another " hatch check" was performed on both doors with satisfactory results. Apparent cause of this event was failure of the O ring to seal properly due to buildup of dry lubricant on the sealing surface.
(309/93-011)
On November 6,1995, while reNeling, an operator noticed a leak at a weld on 3/4 inch piping upstream of a safety valve in the low Pressure Safety Injection / Residual Heat Removal (RHR) l system. Initial evaluation determined that RHR system operability was not compromised.
However, following further inspection, it was determined that a crack of sufficient size to potentially impact system operability was present. Investigation identified a fabrication anomaly and vibration-induced fatigue caused the crack. (309/95-017) -
On January 10,1996, while in hot shutdown during startup, the Low Pressure Safety Injection f
Pumps and Containment Spray Pumps were declared inoperable due to less than the design i
ventilation flow rate. The outside air flow path into the Spray Building was partially blocked when a leak from an overhead heatin6 coil saturated and froze the paper inlet filters.
(309/96-001)
Six LERs were associated with design / construction deficiencies:
On January 21,1993, while at 100% power,'both trains of Control R'oom Ventilatidh declared inoperable as a result of pr.eventive maintenance (PM) for filter replacement inside the B train air handler (AC-1B). Because of damper configuration, during maintenance it is i
d impossible to enernally isolate the AC-1B air handler and maintain a recirculation path. When g
AC 1B is opened, both trains have a direct path to the atmosphere, bypassing the recirculation 4g Q flow. The consequences of this event, which will occur during quarterly PM testing, is minimal since the loss of both trains is less than one hour. Identical events are documented in LERs y
309/93-012,309/93-022, and 309/94-004. (309/93-002) g On July 11,1994, an operator noticed wires protruding from a conduit elbow in the Main Steam Valve House. Closer examination found no fire barrier scalant inside the conduit where it penetrated the wall into the adjacent Reactor MCC Room. A second conduit was also found with no fire barrier scalant. Both conduits were part of a new installation to upgrade Non-Nuclear Safety wiring. (309/94-010)
On April 7,1995 while refueling, the licensee found possible inadequate train separation in the Emergency Core Cooling System (ECCS). A solenoid-operated valve on the Train A component cooling water valve could be actuated from the B CW-cat Spray System train.
Licensee personnel determined that the existing configuration did not conform to the design basis requirements for the PCC system. (309/95-007) 9
t trays. The HM1 cable separation problem was apparently caused by poor construction work.
practices during a 1981 outage. A review of other work packages and field verification found two more wiring discrepancies. (309/94-005)
While conducting a safety valve design review, it was determined that under certain conditions back pressure on the downstream side of two Residual Heat Removal system relief valves could cause these valves to lift at a pressure higher than their setpoint. These valves are credited in Maine Yankee's Low Temperature Over Pressure (LTOP) analysis. An analysis of this condition concluded that existing Technical Specifications and associated procedural controls provide an adequate level of assurance that 10 CFR 50 Appendix G limits would not be exceeded. A plan to more fully evaluate this condition and the generie implications was l
developed. (309/95-012) l L
~ The Cardor Zone 1, Cable Vault fire extingmshing system failed a refueling interval functional test. The system failed to both automatically actuate by smoke detector activation and to remotely actuate utilizing the manual switch at the smoke detector panel in the control room.
On October 24,1995 a subsequent investigation determined that the actuation failures were the.
j result of a wiring defect which had previously avoided detection of a defective mercury switch which formed a portion of the circuit. (309/95-014) 1 l
i During work on a masonry block wall in the Primary Auxiliary Building, it was discovered that contrary to plant design specifications which required the wall to be solid, the wall was hollow.
A technical evaluation of the condition resulted in a determination that during a seismic event l
L the wall could collapse and ;otentially damage safety dass equipment mounted on or near the i
wall including a Containment Hydrogen Purge line which is required to be operable by Plant l
Technical Specifications whenever the plant is critical. Following identification of this deficiency, a review of similar masonry block walls at Maine Yankee was initiated to verify conformance to design specifications. No other safety significant deviations from design specifications were identified as a result of this review. (309/96-005) j l
1 Five LERs reported equipment failures, of which over half were due to the problems with the' steam generator tubes.
L On September 3,1993, during eddy, current testing of #3 steam generator tubes, the licensee found seven defective tubes out of 688 tubes sampled. The apparent root cause of this event is considered to be general corrosion or corrosion cracking due to contaminants and stresses.
Tbc inspection sample was expanded to include all unplugged tubes in #3 steam generator.
All defective tubes were plugged. (309/93-018)
On September 28, 1993, while in a refueling outage, the licensee found that one of four l
available Service Water pumps did not deliver sufficient flow to meet the design basis accident l
analyses. Service Water flow tests enducted after installatian and functional testing of new i
Service Water flow instrumentation found that pump P-29B was degraded; so it was declared l
inoperable. The safety significance of this event is that at power,if train A (P 29A & P-29C) l is lost during a design bases accident and one B train pump, P 29D, was out of service, then only P-29B would be available to remove heat from the component cooling trains. P-29B was scheduled to be overhauled and the cause of the pump degradation was to be determined from overhaul results. (309/93-019)
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On July 16,1994, the plant was shutdown when primary to secondary leakage approached 50 l
gallons per day (GFD). The Technical Specification limit for leakage from any single steam i
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suctioa pressure in the SCC system to isolate the seismic section of SCC from the non-seismic section. On March 15, Maine Yankee determined that the SCC-A-461 valve stem had been
- coupled to the actuator 180 degrees out of alignment and the' disc would not seat. SCC 4
provides cooling to the B Train Emergency Core Cooling System. Failure to meet the leakage criterion would challenge the ability of the SCC system to perform its function during a design basis event following a seismic event that resulted in the failure of the non-seismic portion of SCC. A management review board has been convened to assess the adequacy of Maine Yankee's total response to SCC-A-460/461 and similar issues. (309/95-006) d 23 10 CFR 50.73(a)(2)(lv) ESF Actuations y
As shown in Table 2.1, Maine Yankee submitted 4 LERs under 10 CFR 50.73(a)(2)(iv) reporting ESF actuations.
Three of these LERs also reported RPS actuations (while cridcal). Maine Yankee reported a lower percentage
- of ESF actuations than the remaining plants in the peer group. Table 2.2 shows how Maine Yankee compares -
l to the remaining plants in the peer group with regard to' number of ESF actuations. Table 23 shows the same comparison for the number of RPS actuations. The 4 LERs submitted by Maine Yankee for the report period are characterized as follows:
Two LERs reported ESF actuations caused by equipment failures:
On January 14,1995, Maine Yankee was in the process of returning to full power following a shutdovm to reperur a leak in the feedwater system. At 8:02 a.m., with the plant operating at 99 percent power, the Control Room received an alarm indicating a ground in the main electrical generator. The crew had approximately 50 minutes to determine the cause of the ground before a time delay relay would automatically trip the plant. Following further investigation by Operations personnel and Maintenance workers, other indications of a main generator ground were found and the unit was manually tripped at 8:39 a.m. An investigation of the ground by plant personnel with guidance from the generator manufacturer's representatives revealed the ground occurred in the A phase of the generator stator.
(309/95-001)-
On February 13, 1996, Maine Yankee was operating at 90% power when the reactor automatically scrammed due to a loss of load trip from a high steam generator #3 water level.
The high water level was due to a faulty positioner on the steam generator #3 Main Feedwater Regulating Valve (MFRV). The faulty positioner caused the main feedwater regulat'mg valve to go to the full open position which resulted in overfeeding the #3 steam generator and the resultant trip on high water level. (309/96-003)
One LER reported an ESF actuation as a result of procedural errors:
On May 18,1994, the reactor tripped from 100% power on loss of load due to a main turbine trip caused by a turbine-driven feedwater pump (TDFP) trip. The TDFP tripped on overspeed when high pressure (HP) steam was manually aligned to the TDFP. Earlier, an air leak on a i
345 KV switchyard breaker required decreasing power to 70% to allow breaker isolation.
Reactor power was maintained at 100% while the main turbine load was being reduced. At 80%, the main turbine extraction steam did not have sufficient pressure to run the TDFP and therefore HP steam had to be aligned. The control room r= gal =4 that the HP governor valve was cycling and dispatched an operator to open the HP isolation valve. Since the HP governor valve already had a high open demand signal, the pump tripped on overspeed. The l
root cause of the plant trip was inadequate procedural guidance. (309/94-008) 13
t Table 2.2 Number of LERs Reporting ESF Actuations at Maine Yankee and Other Peer Group Plants Plant Name Docket Number of IIRs Reporting ESF Percentage of Peer Group Actuations ESPs Reponed St. Lucie 1 335 19 0.23 Millstone 2 336 15 0.18 CaMrt Oiffs 2 318 11 0.13 Fort Calhoun 285 11 0.13 Calven Oiffs 1 317 8+
0.10 Palisades 255 7
0.09 St. Lucie 2 389 7
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Table 2.3 Number of LERs Reporting RPS Actuations (while critical) at Maine Yankee and Other Peer.
Group Plants Plant Name Docket Number of LERs Reponing RPS Percentage of Peer Group Actuations RPSs Reponed Calven Qiffs 2 318 9
0.20 St.1.mcie 1 335 9
0.20 Calven Qiffs 1 -
317 7
0.15 Fort Calhoun 285 6
0.13 Minstone 2 336 6
0.13 St. Lucie 2 389 5
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Pahsadas 255 1
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J Since both pulse and reed CEA position alarm functions were disabled for about a month without individual CEA positions being logged and checked for misalignment every four hours, the plant was in noncompliance with TSs during this time. The apparent root cause was determined to be human error in failure to comply with existing administrative controls for removing RPSS cards for troubleshooting. (309/93-021)
-t On January 13,1992, and on February 12,1992, while at 100% power, both trains of control room ventilation were made inoperable when panels were opened for fan maintenance.
Opening the panels prevents effective isolation of both trains of control room ventilation by allowing a path for atmospheric air to enter. This is a violation of plant TS which requires two trains of control room ventilation to be operable when the reactor is critical. The apparent cause was the failure to recognize how the panels affected the ventilation system and not having been classified as a cold shutdown activity. (309/94-001)
Other The facility was operating at 100% power while in the remedial action for Technical Specification 3.23.B.1 due to the motor driven fire pu.up P-4 being out of service for repairs.
During the conduct of surveillance testing for the fire suppression system, the diesel driven fire pump P-5 failed to respond to a manual start. A seccad attempt to start was successful and P 5 was maintained running until a pumper truck from the local fire department was connected to the plant fire suppression system. Pump P-5 was sautdown and a subsequent start test was conducted. The pump failed to start and was declared inoperable. With both fire pumps inoperable, the facility entered the remedial action of Technical Specification 3.23.B.2.
Investigation of the start failure revealed that the starter motor for P-5, which had recently been replaced, was wired incorrectly. This resulted in intermittent starter operation due to improper grounding of the battery charger and starter motor start solenoids. (309/94-013, voluntary)
While flushing the Component Cooling Water (CCW) Heat hh= agers, a non licensed i
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operator misaligned valves resulting in the inboard Secondary CCW (SCCW) heat exchanger having Service Water (SW) aligned to it with no SCCW flow, and the outboard SCCW beat exchanger with SCCW aligned to it with no SW flow. Thus the SCCW system was made inoperable. SW was aligned to both Primary CCW (PCCW) heat crchangers with PCCW 4
aligned to the inboard PCCW heat exchanger. With two SW Prmps in operation (normal configuration) and SW flow aligned to three heat exchangers,it was determined that the ability of the PCCW system to provide adequate cooling is affected during the recirculation mode following a loss of Coolant Accident. (309/94-018)
The Cardox Zone 1, Cable Vault fire emingnWas system failed a refueling interval functional test. The system failed to both automatically actuate by smoke detector activation and to remotely actuate utihzing the manual switch at the smoke detector panel in the control room.
On October 24,1995 a subsequent investigation determined that the actuation failures were the result of a wiring defect which had previously avoided detection of a defective mercury switch which formed a portion of the circuit. (309/95-014) i i
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3.2 Task Description Inadequacies Twenty-one task description inadequ were reported during the time period of interest. Fnmples indude inadequate or undear procedur ek of procedures; misinterpreting oral or written instructions; lack of awareness to changmg req '
ents; and lack of training. The overall number of task description inadequacies 1
j for Maine Yankee was a t the same as the peer group average. The number of task description inadequacies i
in the Operations ar ere considerably higher than the peer group average. Some events have been discussed j
carlier in the report because they fell into a reportability category of interest (see Section 2).
4 3.2.1 Onerations l
l There were eight LERs that reported task description inadequacies associated with operations activities.
{
Shutdowns or Technical Specification Violations 1
As a result of. design review of the component cooling valves, the licensee found 6 unlocked i
i manual valves that were critical to the proper operation of ECCS. All 6 valves were in their proper position and administratively controlled. (309/93-015)
The Nudear Safety, Audit and Review Commit:ee and the Operations Department Manager i
recjuested Maine Yankee Quality Programs Department (MYOPD) to perform an audit ~of the j
completed Emergency Core Cooling System (ECCS) locked valve program while at 100%
l power. During the assessment MYOPD discovered that a one inch globe valve of an ECCS l
subsystem was not locked. The valve was not in its proper ECCS position. An inline valve serving the same function and controlled by a class 'A' procedure was shut but not locked.
Subsequently, the inline valve was locked. TS requires manual ECCS valves (and subsystem valves) to be aligned and locked in the position required for safeguards operation. (309/94-007) k While at 100% power, a review of the procedure that alternates Spray Building Exhaust j
Ventilation Fans, indicated that both fans were off for a brief period of time. TS requires two operable and redundant ECCS trains during power operation. There are no specific TS associated with the fans. However, a Maine Yankee TS Interpretation concludes that Spray Building Exhaust Ventilation must be operable in order for LPSI and CS to be operable. Since both trains are affected by this action, entry into TS is required. A similar event, both fans placed in the off position, had been reported by LER #93-010. Recent NRC interpretations concluded that entry into TS is reportable under CFR. The cause of this event was an inappropriate procedure for alternating fans. (309/94-009)
During a refueling outage, Maine Yankee discovered significant amounts of rust and scale in portions of the Tech Spec required Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler systems. The rust and scale flakes were of sufficient size and quantity that they may have plugged the flow orifices or spray nozzles. This may have rendered the systems inoperable during the last operating cycle. The Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler utilize Aqueous Film Forming Foam (AFFF) to more effectively eninguish oil fires.
The cause of this event is the improper flushing and draining after madvertent actuations of the Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler, which allowed portions of the piping to corrode. (309/95-005) 19
d Table 3.1 Personnel Activity Versus Cause for Personnel Errors at Maine Yankee Causes 4
Intrinsie Task Inadequate Personnel liom,,
o,eripi;o, u. Machine Activity Error inadequacy Interface Total f
Tet t/ Calibration 1
9 1
11 1
Administrative 10 0
0 10 us::-
Maintenanec/
g 6f 3
1 10 1
~
-m Repair Operation 1
Y 8
0 9
s Design 8
0 0
8 4
Installation IN, 1
0 4
Fabrication OM 0
0 3
Construction 1
0 0
1 Radiation 0
0 0
0 Protection Total 33 61 2
56 Table 3.2 Personnel Activity Versus Cause for Personnel Errors at Other Peer Group Plants (per unit)
Causes intrinsic Task Inadequate Personnel go..,
p eripigo, g. u,,3;,,
'etivity Error inadequacy Interface Total t.w h,. ' Calibration 5.1 11.4 0.6 17.1 Administrative 9.3 0.9 0.1 10.3 Maintenance /
44 3.6 0.6 8.2 Repair Operation 4.3 3.6 0.6 83 Design 11.1 0.1 OD 11.2 Installation 0.7 0.3 0.0 th Febsication 1.6 04 OA 1.6 Construction 0.9 0.1 04 1.0 i
Radiation 0.1 0.0 04 0.1 Protection Total 37.1 20.0 1.9 59D 21
i.*
l 4.1 Valves Maine Yankee reported 14 occerrences of valve failures, compared to an average of 4.4 at the other plants in the peer group. The occunences at Maine Yankee include:
While at 100% power, the licensee found two solenoid pilot valves that had exceeded their Environmental Qualification (EO) service life. The pilot valves were part of two normally-closed containment isolation valves that close on a Containment Isolation Signal or a Safety i
Injection Actuation Signal. The isolation valves were declared inoperable upon discovery of the expiration of the solenoid valve's EQ service life. The solenoid valves were replaced and the EO Program updated to reflect their normally energized state. A review of the EO Program found no simhr problems. (309/93-003)
While at 95% power, preparations were made to isolate firemain branch cutout valve FS-289 for repair. This work would also isolate two firehose stations required to be operable by TSs, so compensatory actions were necessary in the form of additional hoses of equivalent capacity routed to the unprotected area from an operable hose station within one hour. However,in j
an effort to expedite the installation of the additional hoses, plant personnel departed from the pre planned hose routing and elected to use a different hose station for the alternate water supply. About twelve hours later, it was discovered that this bose station was inside the tag boundary for the isolation of the branch cutout valve and was thus inoperable. The apparent root cause of this event was human error. ('409/93-013)
See Section 4.2, I&C/ Switches, for an event invoMag failure of a valve's 3-position control switch. (309/94-015)
With the reactor in a cold shutdown condition, plant operators determined that the Emergency Feedwater isolation and regulating valves for #1 Steam Generator were leaking by.
Subsequently it was determined that under accident conditions which require isolation of l
Emergency Feedwater, valve leakage could exceed Safety Analysis assumptions. A root cause investigation identified inadequate maintenance procedures, and inadequate post maintenance testing as the main causal factors for this event. Later analyses showed that plant safety was not significantly compromised by this event. Therefore, this event was changed to information only. (309/94-016, voluntary) 1 I
With the plant in a Refueling Shutdown condition, Maine Yankee determined that two motor operated valves in the High Pressure Safety Injection system were susceptible to the pressure locking phenomena described in NRC Information Notice 95-18. It was postulated that under certain accident conditions, pressure locking of these valves could result in core damage due to a loss of High Pressure Safety Injection cooling. (309/95-008)
Maine Yankee determined that two motor operated valves in the Containment Spray system were susceptible to the pressure locking phenomena descnbed in NRC Information Notice 95-18. It was postulated that under certain accident conditions, pressure locking of these valves could result in loss of containment spray during a small break LOCA. LER 95008, Potential l
Inability of HSI M 54 and HSI M 55 to Perform Their Safety Function, documents two other safety related valves with the same issue. No other nucicar safety related motor operated gate valves were found to be susceptible to this phenomenum. (309/95-010)
With Maine Yankee shutdown and the unit defueled, Emergency Feedwater Isolation Valves EFW A 338, 339, and 340 were disassembled to verify proper disc orientation and seat 1
23
~
that the proximate root cause of this event was a faulty, redundant contact in the 3-position
- control switch for one train of the trip logic circuit; which in turn caused one SOV to de-energize and vent the actuating air required to hold the trip valve shut. (309/94-015)
The plant was in the refueling operations condition with all fuel in the spent fuel pool. Maine Yankee discovered cracks in the lexan cam followers in General Electric (GE) SBM type control switches' installed in 4160 and 6900V breakers. Subsequent inspections revealed cracked and broken cam followers in other applications. Approximately 360 SBM switches are installed in systems critical to safe plant operation.' These 360 switches will be inspected and repaired or replaced, as necessary, prior to the completion of the 1995 refueling outage. Electrical maintenance and engineering personnel were conducting routine inspections and maintenance of 'A' Train 4160V and 6900V GE 'Magna-Blast" circuit breakers. While checking the continuity of the secondary circuit of the auxiliary switch for an Mi 13 operating mechanism, an electrician noticed a crack on the end of a lexan cam follower. The auxiliary switch is a GE type SBM control switch. The electricians inspected sixteen additional breakers to discover if there were any generic implications. They found that approximately two-thirds of the cam followers showed signs of cracking. Three of those cam followers were broken, but only one was non-functional. The non functional cam follower was in a spare contact. On February 28, 1995, Maine Yankee inspected approximately 20 control switches in the main control room for similar cracks. At least one cracked cam follower was found in each switch. These switch '
discrepancies were reported since both trains of Emergency Core Cooling equipment were affected. (309/95-002) s w
The Cardox Zone 1, Cabh Vault fire extinguishing system failed a refueling interval functional test. The system failed to both automatically actuate by smoke detector activation and to remotely actuate utilizing the manual switch at the smoke detector panel in the control room.
A subsequent investigation determined that the actuation failures were the result of a wiring defect which had previously avoided detection of a defective mercury switch which formed a portion of the circuit. (309/95-014) -
4.3 Circuit Bnakers/Fue Maine Yankee reported eight occurrences of circuit breakers / fuses failing, compared to an average of 1.7 at the other plants in the peer group.
While the plant was cooling down in preparation for refueling, a 480 voit ground alarm was received and the D service water pump tripped. The pump's air circuit breaker had opened.Normally a single ground fault will not actuate the RMS 9 device, which serves as an
.overcurrent protection on the breakers in the ungrounded 480 volt buses. This device was designed w:th long-time /short-time trip functions for motor control circuit (MCC) loads and instantaneous trip functions for motor lomi,, closen to cc ordinate with the upstream and downstream protective devices. This coordinatio9 casurcs that an overcurrent condition on a load would not result in de-energizing the entira bus or any upstream load. The RMS-9 trip i
device was certified by GE as a suitable replatement for the EC trip units that were originally installed in GE AK circuit breakers. The AMS-9 trip devices were installed in all AK-25 breakers at MY for both safeguards and non-safeguards 480 voit buses. There are eight AK-25 circuit breakers which controlloads required to mitigate an accident. These include 4 (2 on each of two trains) service water pumps, and 4 (2 on each of two trains) which feed various instrumentation, valves and other equipment necessary for engineered safeguards, in addition 25
l Transition Zone. (309/954)4) The apparent root cause of these events is considered to be general cor:osion or primary water stress corrosion cracking.
Maine Yankee was in a Hot Shutdown Condition during plant startup when the Imw Pressure
+
Safety injecion Pumps and Containment Spray Pumps were declared inoperable due to less than the design ventilation flow rate. The outside air suction flow path to the Spray Building was partially blocked by a leak from an overhead heating coil that saturated and froze the paper inlet filters. (309/%001) i 3
i 4-1 4
1 l
1 i
i j
4 27
j.
i 5.1 Residual Heat Removal Maine Yankee reported eight train failures of the Residual Heat Removal (RHR) system compared to an werage of 2.1 at the other plants in the peer group.
(
Equipment Failure:
a 4
With the plant in a Cold Shutdown Condition, operators were performing a surveillance on the 4
Secondary Component Cooling (SCC) System Non Safeguards Isolation Trip Valves. During the surveillance,it was discovered that one of the valves had failed open due to an apparent 4
l fault in the 2-out-of 2 trip logic circuitry to the solenoid operated valves (SOV) controlling the actuating air to the isolation trip valve actuator. The purpose of these trip valves is to isolate non-safeguards, SCC cooling loads in the event of a postulated seismic event. At the time the i
valve failed open, the SCC subsystem was required to be operable to provide coohng for RHR Train B. Investigation determined that the proximate root cause of this event was a faulty, redundant contact in the 3-position control switch for one train of the trip logic circuit; which in turn caused one SOV to de-energize and vent the actuating air required to hold the trip valve shut. (309/94-015) l With core reload in progress, an operator noticed a 1-2 drop /seemd leak at a weld on 3/4 inch piping upstream of a safety valve in the Low Pressure Safety Inbetion/. RHR system.Jnitial evaluation of this condition resulted in a determination that RHR system operability was not compromised. However, following disassembly and further inspection it was determined that j
a circumferential linear crack of sufficient magnitude to potentially impact system operability was present in the weld. A causal factors investigation identified a fabrication anomaly and l
vibration induced fatigue as causal factors for this condition. (309/95-017)
M sine Yankee was in a Hot Shutdown Condition during plant startup,when the low Pressure Safety injection Pumps and Containment Spray Pumps were declared inoperable due to less j
thas the design ventilation flow rate. The outside air suction flow path to the Spray Building j
was partially blocked by a leak from an overhead heating coil that saturated and froze the paper inlet filters. (309/96-001) i 1'
Other:
l While at 100% power, a review of an experience report concerning temporary disabling of Emergency Core Coolin 6ystem (ECCS) subsystems during valve stroke testing found that the i
report was potentially uliable to Maine Yankee. Operations later concluded that for a brief j
period, during stroke testing of either normally open ECCS pump minimum-flow recirculation valves, both trains of the ECCS low Pressure Safety Injection and Containment Spray j
subsystems must be considered inoperable. These valves had been tested on a monthly basis during ECCS valve tests. The apparent root cause of this event was considered to be failure of the original Technical Specifications to allow for surveillance testing of the minimum flow recirculation valves, even though the surveillance test is required. There were no exceptions 3
in the LCO for ECCS that permitted this testing. This event occurred two more times and was reported in LERs 309/93-009 and 309/93-014. (309/93 001) 3 l
During surveillance testing of Spray Building Exhaua Ventilation Filters, it was determined J
that, for a brief period of time, both trains of Emergency Core Cooling System (ECCS) low Pressure Safety Injection (LPSI) and Contain= cat Spray (CS) subsystems must be considered i
i
l y
3 l
}
5.3/
Fire Protectiba i
i 1
Maine Yankee reported four train failures of the Fire Protection system compared to an average of 0.6 at the other plants in the peer group.
Equipment Failure:
4 l
While the plant was cooling down in preparation for refueling, a 480 volt ground alarm was j
received and the D service water pump tripped. The pump's air circuit breaker had i
opened.Normally a single ground fault will not actuate the RMS-9 device, which serves as an overcurrent protection on the breakers in the ungrounded 480 volt buses. This device was designed with long-time /short-time trip functions for motor control circuit (MCC) loads and t
i instantaneous trip functions for motor loads, chosen to coordinate with the upstream and downstream protective devices. This coordination ensures that an overcurrent condition on a load would not result in de-energizing the entire bus or any upstream load. The RMS-9 trip l
device was certified by GE as a suitable replacement for the EC trip units that were originally i
installed in GE AK circuit breakers. The RMS-9 trip devices were installed in all AK-25 breakers for both safeguards and non-safeguards 480 volt buses. There are eight AK 25 circuit l
breakers which control loads required to mitigate an accident. These include 4 (2 on each of j
two trains) service water pumps, and 4 (2 on each of two trains) which feed various instrumentation, valves and other equipment necessary for engineered safeguards. In addition
]
e one breaker feeds an electric driven fire pump and one is the output breaker of an auxiliary diesel generator which is used to meet 10 CFR Part 50 Appendix R requirements. (309/93-016) i With Maine Yankee in a shutdown and defueled condition, the Cardox Zone 1, Cable Vault l
+
i l
fire extinguishing system failed a refueling interval functional test. The system failed to both automatically actuate by smoke detector activation and to remotely actuate utilizing the manual switch at the smoke detector panelin the control room. A subsequent investigation determined that the actuation failures were the result of a wiring defect which had previously avoided
[
detection of a defective mercury switch which formed a portion of the circuit. (309/95-014) i i
Other:
i The facility was operating at 100% power while in the remedial action for Technical Speci6 cation 3.23.B.1 due to the motor driven fire pump (P-4) being out of service for repairs.
4 j
During the conduct of surveillance testag for the fire suppression system, the diesel driven fire l
pump (P-5) failed to respond to a manual start. A second attempt to start was successful and
]
. P-5 was maintained running until a pumper truck from the local fire department was connected to the plant fire suppression system. P 5 was shutdown and a subsequent start test was conducted. The pump failed to start and was declared inoperable. With both fire pumps inoperable, the facility entered the remedial action of Technical Specification 3.23.B.2.
Additionally, an Unusual Event was declared due to a loss of all fire protection pumps.
Investigation of the start failure revealed that the starter motor for P 5, which had recently been replaced, was wired incorrectly. This resulted in intermittent starter operation due to improper grounding of the battery charger and starter motor start solenoids. (309/94 013, voluntary)
During a refueling outage, Maine Yankee discovered significant amounts of rust and scale in portions of the Tech Spec required Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler systems. The rust and scale flakes were of sufficient size and quantity that they may 31
ll.
The plant was in a refueling shutdown conducting surveillance testing. The Secondary Component Cooling (SCC) system non-safeguards isolation valves, SCC-A-460 and SCC-A-461, failed their in system combined seat leakage test. They close on low pump suction pressure in the SCC system to isolate the seismic section of SCC from the non-seismic section. Maine Yankee determined that the SCC-A-461 valve stem had been coupled to the actuator 180 degrees out of alignment and the disc would not seat. SCC provides cooling to the B Train i
ECCS. Failure to meet the leakage criterion would challenge the ability of the SCC system to perform its function during a design basis event following a seismic event that resulted in the
(
failure of the non-seismic portion of SCC. A management review board was convened to assess the adequacy of Maine Yankee's total response to SCC-A-460/461 and similar issues.
(309/95-006)
Maine Yankee was operating at 90% power when the Shift Operating Supervisor (SOS) restored the 'out of service' Secondary Componett Cooling (SCC) heat exchanger to operation.
The SOS did not rem-ai= that one vent valve was an ECCS valve, required to be shut and locked per TS. Two procedures were referenced for final position, but one procedure was incorrect and had not been updated and the other was misread, which resulted in the valve being inappropriately positioned to one turn open and locked. A Non-Licensed Operator (NPO) was performing a surveillance on ECCS alignment and discovered that this vent valve was not positioned correctly per the procedure. (309/96-002)
Table 5.1 Summary of Trahi Failures at Maine Yankee and Other Peer Group Plants
?
Number of Ratio of System Average System and and Train Number of Train Failures to the System and System Failures Average of the Train Failures Peer Group at Peer Group Plants
[itEIAdiEOtEE&aIYb @$[MN$$! $$b33NIld If$$$$ N O M S m nauw my 4 w.s g g. nem,.ag un14! ssggyno&g ~;i 4 Containment s a. pray 3 "Jef F ^18rjasK r W5.03MS iire Protodice 2 J l'f L'I'E4 -[.J h'b,U. ;N?s ! A,' 04Gd,7
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3.1 1.6 Essential Raw 5
1.6 3.1 Cooling / Service Water 1
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l I
6.0 ANALYSIS OF NRC PERFORMANCE INDICATOR DATA This section contains an analysis of the Performance Indicators for Maine Yankee for the period beginning the fourth quarter of 1994 through the third quarter of 1996. Figures 6.1 and 6.2 contain the performance indicator displays from the Third Quarter 1996 Report. Additional information on PI report formats and calculational methods can be found in the latest Performance Indicator report published by AEOD.
l All negative trends and deviations that have a medium or high statistical significance were reviewed to determme if they have been covered elsewhere in this report. If they are not already covered by a prior section, the LERs or other data was reviewed and the results are described in this section.
6.1 Analysis The displays indicate the following negative self-trends or peer group deviations.
Administrative Control Problems Negative deviation from the peer group during operations (Medium Significance)
This category includes management and supervisory deficiencies that affected plant programs or actintieg Examples include poor planning, lack of management controls, and weak or j
mcorrect procedures.
[
ltems in this category were discussed in Section 3.
Forced Outage Rate Negative short term self-trend and negative deviation from the peer group (High Significance)
Based on the monthly operating reports, the forced outage rate is the number of forced outage hours divided by the sum of unit service hours plus the number of forced outage hours.
The chart on the following page provides a brief description of Maine Yankee outages.
i l
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MAINE YANKEE Asfuesne R
Operation m f,,,
g BMAM Qus % Date Nut Shown UWng Op.Cyck 3333 1
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m m h k o1 33.f 39 34.9 34 3 I s.f in on De e4J te.t E3 Year.CQuerter tht' tu Year. Querter Egulpment Formed outageet 1000 CommercialCstucal Heure Fosted Outage Rate (%l g
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Figuet 6.1 Performance Indicators for Maine Yankee 4
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APPENDIX A: LISTING OF MAINE YANKEE LERS BY CATEGOI{Y i
1
.___m_.m.
__--_m._.
..__._.m
.m.-
IRC/$ witches 1 309/93 006 2 309/94 006 3 309/94 015 4 309/95-002 5 309/95 014 Circuit Breakers / Fuses 1 309/93 016 2 309/ W 006 3 309/94 006 Heat Enchancers 1 309/93 018 2 309/94 012 3 309/95 004 4 309/96 001 SYSTDI FAILLRES FM MIME YANKEE Realchaal Neat Removal (Code SF) 1 309/93 001 2 309/93 009 3 309/93 010 4 309/93-014 5 309/94 009 6 309/94-015 7 309/95 017 8 309/96 001 Contalrunent Soray (Code DE) 1 309/93-001 2 309/93 009 3 309/93 010 4 309/94 009 5 309/95 003 6 309/95 010 7 309/ % 001 Fire Protection (Code KF) 1 309/93 016 2 309/ W O13 3 309/95 005 4 309/95 014 Component Coolina Water (Code CA) 1 309/93 023 2 309/94 015 3 309/94 018 4 309/95-006 5 309/95-007 6 309/ @ 002
+
ST5 TEN OCCLNWENCES AT WINE ypwrF (No TRAIN FAILLRES SPECIFIED)
Connonent Coolina Water 1 309/93 015 2 309/93 023 3 309/ W 007 4 309/94 015 5 309/94 018 6 309/95-006 7 309/95 007 8 309/95-015 9 309/ W OO2 Fire Protection 1 309/93 004 2 309/93 013 3 309/93 016 4 309/94 010 5 309/94 013 6 309/95-005-7 309/95 014 Steam Generator 1 309/93-018 2 309/94 002 3 309/ W O11 4 309/ W O12 5 309/95-004 6 309/96 003 Contahment torav 1 309/93 001 2 309/93-009 3 309/93 010 4 309/ W 009 5 309/95 003 6 309/95 010.
7 309/ W 001 A-3
-rb
- __m,
l l
l APPENDIX B: ABSTRACI'S FOR MAINE YANKEE LERS
~
l l
1 DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE
.....................13 0 316...... 0...... 0 3. /. 08 /. 9 3..
0 9304 309....1993...... 004 POWER LEVEL - 100%. On March 8,1993 at 0630 while at full power, upper level Spray Pump Building Fire Door (FD) 103 became inoperable when heating ver.tllation unit HV-7 was tagged out of service for routine maintenance. Compensatory actions required by the plant's technical specifications were not implemented until the inoperable door was discovered at 0045 on March 9, 1993. When the inoperable status of the fire door was recognized, HV-7 was returned to service to rectify the condition. During the pertod that the fire door was inoperable, the door was closed but the differential pressure across the door exceeded the capability of the door closing mechanism to reliably latch the door. The root cause of the incident is considered to be personnel error. The planned corrective action will be to place precautions in the ventilation procedures to alert operators to the fact that abnormal ventilation configurations can cause fire doors to become inoperable.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE
. 09.. 1993...... 005.......... 0..... 93 0412 02 4 6......0..... 03 /.08./.9 3 3
POWER LEVEL - 100%. On March 8,1993 at 1230 while at full power, the NRC Resident Inspector notified the control room that 5 manual valves which were necessary to assure emergency and auxiliary feedwater flow from the primary water source to the steam generators did not appear to have the adninistrative controls required by the plant's Technical Speelfications. The 5 valves were aligned properly and controlled by procedure but due to a procedural deficiency they were not locked as required by the plant's Technical Specifications. A subsequent review of all of the valves in the emergency and auxiliary feedwater flow path identified 3 additional valves which should have been fitted with locking devices but were not. During operation at power the emergency ano auxiliary feedwater flow path manual valves must be aligned and locked in the position required for reactor core energy removal. The root cause of this event was a procedural deficiency. The deficiency resulted from a misinterpretation of the policy governing locked valves. The policy was subsequently clarified. but the eff 3ct of the policy clarification on the p@edure governing the periodic surveillance of the subject valves was not recognized. The affected valves have been locked and the controlling procedure has been revised. There was no safety significance to this event because all of the valvc: were confirmed to have been procedurally controlled in their proper position for reactor core energy remova.
\\\\
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309....1993...... 006......... 0..... 9304 200213.......0...... 02./.22./.93..
POVER LEVEL - 100%. This informational LER is being submitted to describe the findings of Maine Yankee (NY)
Electrical Maintenance while conducting preventative maintenance on Reactor Trip Circuit Breakers (type AK-25) on 02/22/93. During the performance of MY procedure 5-77-2. INSPECTION AND REPAIR OF GENERAL ELECTRIC AK-25 REACTOR TRIP CIRCUIT BREAKERS. a defective cutof f switch actuator (paddle) was detected on a Reactor Trip Circuit Breaker.
The defect was identified as a broken cut-off switch actuator. The cut-off switch is part of the breaker control circuit which provides the anti-punp feature. This feature prevents repeated closure attempts if a trip signal is present during breaker closure. The breaker is tripped by other means. The remaining ten RTB cut-off switches were inspected and three additional cracked actuators were discovered. Of these three, only one breaker was in service, i
the other two were spares. A determination was made about the operability of the breaker with the cracked paddle
)
being able to perform it's intended function. The breaker was considered operable because the open/ trip capability was not compromised. The faulty switch on the breaker with the broken paddle was replaced and the trip breaker tested successfully. All RTB's were inspected for defective paddles and all cracked paddles were replaced. The root cause of the defect was determined to be cyclic fatigue. GE will also provide a written failure analysis. One i
stellar occurrence was reported by LER 83-036 that documented cracked shunt trip paddles, which is a different sub-component of the AK-25 breaker.
i B-3
l l
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309....1993...... 0.11........ 0..... 930629 02 55......0...... 05/.26/.93..
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POWER LEVEL - 100%. At 1030 on Tuesday May 25, 1993 Nuclear Plant Operators (NPO's) completed a routine Containment Inspection in accordance with (IAW) Maine Yankee (MY) Procedure 1-200-11 CONTAINMENT INSPECTION. Following the Containment Inspection a personnel " hatch check" was performed IAW MY Procedure 3-1-13 PERSONNEL AIR LOCK 000R SEAL i
LEAK TEST. The " hatch check" was completed at 2230 on the same day. The integrity of the inner door of the CTMT hatch was determined to be compromised. The integrity of the outer door was determined to be sound. CTMT integrity
)
I was assured as long as the outer door was sealed. On Wednesday May 26, 1993 at 1037 the CTMT hatch outer door was opened for maintenance on the inner door. TS 3.0 A.2, was entered. The time required to open and close the outer door was less than five (5) minutes so no shutdown was comenced. At 1039 the outer hatch was secured and TS 3.0 A.2. was exited. The inner hatch "0" ring was cleaned, inspected, lubricated in place, and the door was placed back l
in service. The outer door was reopened at 1040 and reclosed at 1041 TS 3.0 A.2. was entered and exited once again, At 1130 of the same day a " hatch check" was performed on both doors IAW MY procedure 3-1-13 with satisfactory l
results. Previous LER's have been submitted by MY for this type of event. LER 80-002 was written to describe a l
" hatch check" failure and LER 83-034 reported brief openings of an inner hatch while the outer hatch was inoperable.
l The cause of this event is the failure of the "0" ring to properly seal uniformly due to the build up of dry lubricant on one area of the sealing surface, e...................................................................
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 300......19 9 3...... 0.12......... 0..... 9 3 063 00.12 0...... 0...... 0 5/. 2. 7 /.9 3 l
POWER LEVEL - 100%. This LER is written to provide information about preventative maintenance of control ventilation which requires entry into Technical Specification 3.0.A.2.
On May 27, 1993, both trains of Control Room Ventilatton were declared inoperable for a brief period of time. The inoperability of both trains was a result of preventative l
maintenance (PM) for filter replacement, internal to "B" train air handler (AC-18). Because of damper configuration, it is impossible to externally isolate the AC-18 air handler and maintain a recirculation path. When AC-18 is opened, both trains via FN-11A or FN-118 nave direct paths to the atmosphere, which bypasses the l
recirculation flow. The consequences of this event, which occurs quarterly, is minimal since the loss of both l
trains is of short duratton (less than I hour - no shutdown initiated) for the PM.
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DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3.09....1993......013.......... 0..... 9307230046...... 0..... 06/.18./93 l
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POWER LEVEL - 095%. On June 18, 1993, with the plant at 95% power, preparations were made to isolate firemain branch l
cutout valve FS-289 for repair. It was recognized this work would also isolate two firehose stations required to be operable by Technical Specifications and that compensatory actions were necessary. With a required firehose station inoperable, Technical Specifications require routing of auditional hoses of equivalent capacity, to the unprotected area from an operable hose station, within one hour. The Fire Protection Coordinator (FPC) and the Shift Operating Supervisor (505) responsible for isolating and tagging out the cutout valve each performed an independent review of system drawings to identify other operable hose stations for supplying the additional hoses. However, in an effort to expedite the installation of the additional hoses, the FPC departed from his pre-planned hose routing and elected to use a different hose station for the alternate water supply. Approximately twelve hours later, it was discovered that this hose station was inside the tagging boundary for the isolation of the branch cutout valve; and thus was itself inoperable. Imediate corrective action was taken to re-route the hose to an operable station. However, for approximately 12-1/2 hours, Maine Yankee was in noncompliance with Technical Specification 3.230, The root cause of l
this event was htsnan error on the part of the FPC.
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ese........ee......seeeeeee.eee.******.******.*e.**ee *e.*..e.**.**e DOCKET YEAR LER NUMBER REVISICN DCS NUMBER NSIC EVENT DATE 3 09....199 3......
0.17........ 0.... 9309280.168........0...... 08/.15/.93 POWER LEVEL - 000%. This voluntary LER is being submitted to supply information related to the discovery of a condition which deviates from the electrical separation design criteria specified in Main Yankee's Final Safety Analysis Report. On August 15, 1993 while performtng refueling shutdown protective relay preventative maintenance, an emergency diesel generator output breaker voltage relay discrepancy was discovered. Further review also revealed that both the discrepant relay and the corresponding relay on the other emergency generator shared a connon coil circuit ground return wire. Although the use of a connon ground return wire complied with the AEC General Design Criteria when the plant was licensed and thus is within the plant's design basis, its existence represents a deviation from the electrical separation design criteria specified in Maine Yankee's Final Safety Analysis Report.
fhe cause of the event is a discrepancy in the plant's original design. A temporary modification has been implemented to provide a separate ground return path for each relay and a design change will be processed to make the change permanent. Screening criteria was developed and implemented to detemine if any similar circuits shared a j
consnon ground return wire. No similar wiring problems were identified.
DOCKET YEAR LER NUMBER REVISION DCS NUMVR NSIC EVENT DATE 309....1993..... 018 0
0
................. 9310070281......................
09/.03/.93..
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POWER LEVEL - 000%. On September 3.1993, during eddy current testing of f 3 steam generator tubes. Maine Yankee l
found 7 defective tubes in a 688 tubes sample. Plant Technical Specifications 4.10 requires reporting of this condition. The root cause of this event is considered to be general corrosion or corrosion cracking due to contaminants and stresses. The inspection sample was expanded to include all unplugged tubes in #3 steam generator.
All defective tubes were clugged.
l DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE l
3 09....199 3...... 0.19......... 0..... 9 31 10 2 0171...... 0...... 09. /.2 8. / 9 3 i
POWEP. LEVEL - 000%. On September 28,1993. while in a refueling outage. Msine Yankee deterutned that one of four available Service Water pumps (P-29A,0.C,0) did not deliver sufficient flow capacity to meet the design basis accident analyses. Service Water flow tests were conducted on September 23. 1993 after installation and functional I
testing of new Service Water flow instrumentation. On September 28,1993, after analyzing the new data, it was determined that P-29B was degraded. P-298 was declared inoperable. The safety significance of this event is that at power, if train A (P-29A & P-29C) is lost during a design bases accident and one B train pump, P-290. was out of l
service, then only P-29B would be available to remove heat from the component cooling trains. P-298 is scheduled to be overhauled. The cause of the pump degradation will be determined from overhaul results.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE l
309..1993.......020.......... 0.... 9 312020.119....... 0.......10/.12./.93..
POWER LEVEL - 002%. This informational LER is submitted to document events related to a deviation from the Technical Specification requirements for entry into the Power Operation Condition (condition 7). On October 11.1993 while l
returning to power operations following a refueling outage, condition 7 was unintentionally entered prior to l
Technical Specification prerequisites for the condition being completed. Entry into the Power Operating Condition (condition 7) is defined in the plant's Technical Specificaticn as occurring when the reactor is critical and indicated power on the Power Range Nuclear Instrumentation (PRNI) exceeds 2%. At the time of the event, operators were relying on Wide Range Nuclear Instrunents for power level indication and they were not aware that Technical Specifications required that PRNI be used for determining entry into the Power Operating Condition. Plant Technical Specifications also require the establishnent of the three auxiliary and emergency feedwater flow paths prior to entry into the power operating condition. Prior to estabitshnent of the final emergency feedwater flow path, 2%
power as indicated on the PRN! digital volt meter was exceeded. The cause of this event is a failure to recognize that plant procedures did not incorporate the technical specification definition of the power operating condition.
I In order to prevent recurrence, plant procedures have been revised to specify that PRN! shall be used to determine the 2% power point of entry into the Power Operating Condition. The need for providing additional guidance to cperators concerning the power level indications to be observed through each segment of the operating range will j
also be evaluated, B7 l
F MAINE YANKEE - 1994 DOCKIT YEAR LER NUMB:R REVISION DCS NUMBER NSIC EVENT DATE 309....1994...... 0 01........ 0..... 9. 4 0 2.18 0188....... 0...... 01/. 0 5/.9 4 POVER LEVEL - 100%. On A nuary 13, 1992, and on February 12, 1992, with the plant in the power operating condition, both trains of control room ventilation were made inoperable when panels were opened for fan maintenance. Opening the panels prevents effective isolation of both trains of control room ventilation by allowing a path for atmospheric air to enter. Plant Technical Specification 3.25.B requires two trains of control room ventilation to be operable when the reactor is critical. Therefore the plant was in a condition prohibited by Technical Specifications. The cause for this event appears to have been a failure to recognize how opening the panels affected the ventilation system and not having the activity classified as a cold shutdown activity. Planned maintenance activities requiring the removal of these panels have been scheduled for times when the plant is in cold shutdown.
DOCKET YEAR LER NUMBER REv!SION DCS NUMBER NSIC EVENT DATE 309....199.4.....002...........1.... 9.407060085......0..... 02/.0.7/.94 4
POVER LEVEL - 100%. This LER is being sutrnitted to supply information related to inadequate configuration control in the design and operation of Maine Yankee's Steam Generator Blowdown System which resulted in operation of the plant in an unanalyzed condition. On December 3, 1993. Maine Yankee recognized that station design and a &inistrative controls did not prevent operation of the Steam Generator Blowdown System outside the bounds of Maine Yankee's transient analysts. Imediately following identification of this discrepancy, a&inistrative controls were stablished to e sure conservap1h operation of the Blowdown System. At that time, Maine Yankee had determined that i
the blowdown system was operated"in an unanalyzed condition, but that this condition did not significantly compromise plant safety. Further analysis of the situation revealed that the fluid conditions post trip may change such that more mass would be traasported from the steam generators than was originally considered. Thus, on February
- 7. 1994 Maine Yankee determined that the Steam Generator Blowdown system had been operated in an unanalyzed condition which may have significantly affected plant safety. Stricter a@inistrative controls were imediately set to limit full power blowdown flow rates. A thorough analysis of the safety consequences of this event has been completed. The analysis has concluded that the plant did not operate in an unsafe condition.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NS!C EVENT DATE 3.09....1994...... 003..........1.... 9 4 0. 7 06003 5......0...... 02/.2 2./.9 4 POVER LEVEL - 100%. The Maine Yankee Service Water system provides cooling to the Component Cooling system which cool Emergency Core Cooling equipment. Maine Yankee's response to GL 8913 included installing flow measuring devices in the Service Water system and a review of Service Water Operational Performance Inspections at other plants. Through this review, heat exchanger flow imbalance was identified as an issue. Further analysis of flow data collected at Maine Yankee revealed that the Service Water system is susceptible to flow imbalances due to heat exchtnger inlet strainer differential pressures and design differences. The inlet strainer differential pressures lead to flow imbalances which require an penalty in the system's safety analysis. As a result, on February 22, 1994, Maine Yankee concluded that in the past. Service Water flow rey not have : net design basis requirements with wann river water temperatures. During the winter months the river water temperatures are low enough to provide sufficient cooling to the Component Cooling water heat exchangers. However, in the sumer, the river water temperatures rise above that required to sufficiently cool the Component Cooling Water heat exchangers under all design conditions. Thus, Maine Yankee may have operated the Service Water system outside its current design basis.
Maine Yankee is investigating several options to assure the Service Water system meets design requirements during sumer months including: improving the screening of the service water pu@ intake water, igrowing service water pug perfonnance, improving the flow measuring instrumentation, reviewing the design basis calculations, and establishing heat exchanger differential pressure limitts.
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DOCKET YEAR LER NUMBER REVIS!DN DCS NUMBER NSIC EVENT DATE 309... 199.4..... 007..........0..... 9 4 062204 06.......0...... 0.5/.17/.9 4 POWER LEVEL - 100%. The Nuclear Safety Audit and Review Comittee (NSARC) and the Operations Department Manager requested Maine Yankee Quality Programs Department (MYQPD) to perform an audit of the completed Emergency Core Cooling System (ECCS) locked valve program. During the assessment ny0PD discovered that a one inch globe valve of an i
ECCS subsystem was not locked. The valve (SCC-18) was not in its proper ECCS position. Aninlinevalve(SCC-19)
{
serving the same function and a@iinistratively controlled by a class "A" procedure was shut but not locked.
l Subsequently, SCC-19 was locked in lieu of SCC-18. The function of the valves were to isolate Secondary Component l
Cooling (SCC) water to the chemical addition tank in the SCC system. Maine Yankee Technical Specifications (Tech.
Specs.) requires manual ECCS valves (and subsystem valves) to be aligned and locked in the position required for I
safeguards operation. SCC-19 was imediately locked.
l DOCKET YEAR LER NUMBER REVISION DCS NUMBER NS]C EVENT DATE i
j 309... 1994........008......... 0..... 9406220388.......0..... 0.5/.18./94 l
l POWER LEVEL - 100%. On May 18,1994, the reactor tripped from 100% power on loss of load due to a main turbine trip.
The main turbine tripped due to a trip of the turbine-driven feedwater pump (TDFP). The TDFP tripped on overspeed l
when high pressure (HP) steam was manually aligned to the TDFP. Earlier, an air leak on a 345 KV switchyard breaker l
required decreasing power to 600 MWE (70% rated pcwer) to allow breaker isolation. Reactor power was maintained at l
100% while the main turbine load was being reduced. At 80% rated output, the main turbine extraction steam did not have sufficient pressure to run the TOFP and therefore HP steam had to be aligned. Tha control room recognized that the HP governor valve was cycling and dispatched an operator to open the HP isolation valve. Since the HP governor valve already had a high open demand signal, the pump tripped on overspeed. The root cause of the plant trip was inadequate procedural guidance. Changes have been made to the procedure to prevent recurrence. A more formal root cause evaluation may include reconenendations to further enhance operating the pump under all conditions.
l DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309.......94....... 009..........
0 19
..... 9408110294............
0..... 0.7/.03/.94 l
POWER LEVEL - 100%. On July 3,1994. a review of the procedure, that alternates Spray Building Exhaust ventilation r
Fans, Indicated that both fans are off for a brief period of time during this evolution. Technical Specification (TS) 3.6 C.2 requires two operable and redundant ECCS trains during power operation. There are no specific TS associated with the fans. However, a Maine Yankee TS Interpretation concludes that Spray Building Exhaust Ventilation must be operable in order for LPSI and CS to be operable. Since both trains are affected by this action, entry into TS 3.0 A.2 is required. The time required to alternate the fans is so short that no shutdown is comenced. A similar event, both fans placed in the off position, has been reported by LER #93-010. Recent NRC Interpretations concluded that entry into TS 3.0 A.? is reportable under 10 CFR 50.73. The cause of this event was an inappropriate procedure for alternating fans. A new section has been added to the procedure to change the sequencing so as to avoid this problem.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309... 1994.... 0.10.........1.... 9.508290028......0...... 0.7/.11/.94 POWER LEVEL - 100%. At 1250 on July 11, 1994, an Auxillary Operator, while performing his normal rounds, noticed wires protruding from a conduit elbow in the Main Steam Valve House. Upon closer examination, he found that there was no fire barrier sealant material inside the conduit where it penetrated the wall into the adjacent Reactor MCC Room. He then noticed a second conduit with no fire barrier sealant material within it. Both conduits were part of a new installation for upgrading Non-Nuclear Safety wiring systems in the plant. The Auxiliary Operator called the i
Control Room and was directed to remain at the penetrations as a fire watch. The penetrations were then properly sealed with fire barrier sealant material. All penetrations which were part of that conduit installation were inspected to ensure that they were properly sealed. No further discrepancies were found.
B-11 1
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APPENDIX B: AESTRACTS FOR MAINE YANKEE LERS t
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DOCKET YEAR LER NUMBER REVISION DCS NUMBER NS!C EVENT DATE 309....1993.....s.004.......... 0... 9304130316......0...... 03/.08/93 1
POWER LEVEL - 100%. On March 8,1993 at 0630 while at full power, upper level Soray Pump Building Fire Door (FD) 103 became inoperable when heating ventilation unit HV-7 was tagged out of service for routine maintenance. Compensatory actions required by the plant's technical specifications were not implemented until the inoperable coor was 4
discovered at 0045 on March 9, 1993. When the inoperable status of the fire door was recognized, HV-7 was returned to service to rectify the condition. During the period that the fire door was inoperable, the door was closed but the differential pressure across the door exceeded the capability of the door closing mechanism to reliably latch j
the door. The root cause of the incident is considered to be personnel error. The planced corrective action will be to place precautions in the ventilation procedures to alert operators to the fact that abnormal ventilattra configurations can cause fire doors to become inoperable.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309.....1993..... 005........ 0..... 9304120246...... 0.... 03./.08/.93 POWER LEVEL - 100%. On March 8,1993 at 1230 while at full power, the NRC Resident inspector notified the control room that 5 manual valves which were necessary to assure emergency and auxiliary feedwater flow from the primary water source to the steam generators did not appear to have the a htnistrative controls required by the plant's Technical Specifications. The 5 valves were aligned properly and controlled by procedure but due to a procedural deficiency they were not locked as required by the plant's Technical Specifications. A subsequent review of all of the valves in the emergency and auxiliary feedwater flow path identified 3 additional valves which shoulo have been fitted with locking devices but were not. During operation at power the emergency ano auxiliary feedwater flow path manual valves must be aligned and locked in the position required for reactor core energy removal. The root cause of this event was a proceoural deficiency. The deficiency resulted from a misinterpretation of the policy governing locked valves. The policy was subsequently clarified, but the eff3ct of the policy clarification on the p.9cedure governing the periodic surveillance of the subject valves was not recognized. The affected valves have been locked and the controlling procedure has been revised. There was no safety significance to this event because all of the valves were confirmed to have been procedurally controlled in their proper position for reactor core energy remova;.
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DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309... 1993...... 006........ 0..... 93042002.13......0...... 02./.22./.93..
POWER LEVEL - 100%. This infomationel LER is being submitted to describe the findings of Maine Yankee (MY)
Electrical Maintenance while conducting preventative maintenance on Reactor Trip Circuit Breakers (type AK-25) on 02/22/93. During the performance of NY procedure 5-77-2. INSPECTION AND REPAIR OF GENERAL ELECTRIC AK-25 REACTOR TRIP CIRCUIT BREAKERS, a defective cutoff switch actuator (paddle) was detected on a Reactor Trip Circuit Breaker.
The defect was identified as a broken cut-off switch actuator. The cut-off switch is part of the breaker control circuit which provides the anti-pump feature. This feature prevents repeated closure attempts if a trip signal is present during breaker closure. The breaker is tripped by other means. The remaining ten RTB cut-off switches were inspected and three additional cracked actuators were discovered. Of these three, only one breaker was in service, the other two were spares. A detemination was made about the operability of the breaker with the cracked paddle being able to perform it's intended function. The breaker was considered operable because the open/ trip capability was not compromised. The faulty switch on the breaker with the broken paddle was replaced and the trip breaker tested successfully. All RTB's were inspected for defective paddles and all cracked paddles were replaced. The root cause of the defect was determined to be cyclic fatigue. GE will also provide a written failure analysis. One stellar occurrence was reported by LER 83-036 that documented cracked shunt trip paddles, which is a different sub-component of the AK-25 breaker, a
B-3
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DOCKET YEAR LER NUMBER REVISION DCS NUMBER NS!C EVENT DATE 309... 1993...... 0.11........ 0..... 9.3062902.55......0...... 05/.26/93 POWER LEVEL - 100%. At 1030 on Tuesday May 25, 1993 Nuclear Plant Operators (NPO's) completed a routine Containment inspection in accordance with (IAW) Maine Yankee (MY) Procedure 1-200-11 CONTAINMENT INSPECTION. Following the Containment Inspection a personnel " hatch check" was performed I AW MY Procedure 3-1-13 PERSONNEL AIR LOCK DOOR SEAL LEAK TEST. The " hatch check" was completed at 2230 on the same day. The integrity of the inner door of the CTMT hatch was determined to be compromised. The integrity of the outer door was detemined to be sound. CTMT integrity was assured as long as the outer door was sealed. On Wednesday May 26,1993 at 1037 the CTMT hatch outer door was opened for maintenance on the inner door. TS 3.0 A.2. was entered. The time required to open and close the outer door was less than five (5) minutes so no shutdown was consnenced. At 1039 the outer hatch was secured and TS 3.0 A.2. was exited. The inner hatch *0" ring was cleaned, inspected, lubricated in place, and the door was placed back in service. The outer door was reopened at 1040 and reclosed at 1041 TS 3.0 A.2. was entered and exited once again.
At 1130 of the same day a " hatch check" was performed on both doors IAW MY procedure 3-1-13 with catisfactory results. Previous LER's have been submitted by MY for this type of event. LER 80-002 was written to describe a
" hatch check" failure and LER 83-034 reported brief openings of an inner hatch while the outer hatch was inoperable.
The cause of this event is the failure of the "0" ring to properly seal uniformly due to the build up of dry lubricant on one area of the sealing surface.
e...................................................................
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSit EVENT DATE 309......1993...... 0.12.........
0..... 93 063 00.12 0......0...... 0 5/.2 7/.9 3 POWER LEVEL - 100%. This LER is written to provide information about preventative maintenance of control ventilation which requires entry into Technical Specification 3.0.A.2.
On May 27, 1993, both trains of Control Room Ventilation were declared inoperable for a brief period of time. The inoperability of both trains was a result of preventative maintenance (PM) for filter replacement, internal to "B" train air handler (AC-18). Because of damper configuration, it is impossible to externally isolate the AC-18 air handle and maintain a recirculation path. When AC-1B is opened, both trains via FN-11A or FN-11B nave direct paths to thf atmosphere, which bypasses the recirculation flow. The consequences of this event, which occurs quarteriy, is minimal since the loss of both trains is of short duration (less than I hour - no shutdown initiated) for the PM.
e...................................................................
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 30
- e. 9... 1993..... 0.13......... 0..... 9 3 0 72 3 004 6......
0..... 06./.18/.93..
POWER LEVEL - 095%. On June 18, 1993, with the plant at 95% power, preparations were made to isolate firemain branch cutout valve FS-289 for repair. It was recognized this work would also isolate two firehose stations required to be operable by Technical Specifications and that compensatory actions,ere necessary. With a required firehose station inoperable, Technical Specifications require routing of soditional hoses of equivalent capacity, to the unprotected ares from an operable hose station, within one hour. TheFireProtectionCoordinator(FPC)andtheShiftOperating Supervisor (505) responsible for isolating and tagging out the cutout valve each performed an independent review of system drawings to identify other operable hose stations for supplying the additional hoses. However, in an effort to expedite the installation of the additional hoses, the FPC departed from his pre-planned hose routing and elected to use a different hose station for the alternate water supply. Approximately twelve hours later, it was discovered that this hose station was inside the tagging boundary for the isolation of the branch cutout valve; and thus was itself inoperable. Immediate corrective action was taken to re-route the hose to an operable station. However, for approximately 12-1/2 hours. Maine Yankee was in noncogliance with Technical Specificatien 3.230. The root cause of this event was human error on the part of the FPC.
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j DOCKET YEAR LER NUMBER REv!SION DCS NUMBER NS!C EVENT DATE 3 09....199 3..... 0.17........0..... 9 3 0928 0168.......0..... 08/.15/.93 j
POVER LEVEL - 000%. This voluntary LER is being submitted to supply information related to the discovery of a condition which deviates from the electrical separation design criteria specified in Main Yankee's Final Safety Analysts Report. On August 15, 1993 while performing refueling shutdown protective relay preventative maintenance, an emergency diesel generator output breaker voltage relay discrepancy was discovered. Further review also revealed that both the discrepant relay and the corresponding relay on the other emergency generator shared a comon coil circuit ground return wire. Although the use of a comon ground return wire complied with the AEC General Design Criteria when the plant was licensed and thus is within the plant's design basis, its existence represents a deviation from the electrical separation design criteria specified in Maine Yankee's Final Safety Analysis Report.
i The cause of the event is a discrepancy in the plant's original design. A temporary modification has been l
implemented to provide a separate ground return pcth for each relay and a design change will be processed to make the change permanent. Screening criteria was developed and implemented to determine if any similar circuits shared a comon ground return wire. No similar wiring problems were identified.
DOCKET YEAR LER NUMBER REv!SION OCS NUMBER NSIC EVENT DATE 309 1993 018 0
9
................................... 31007028.1 0
09
................/03/.93 POWER LEVEL - 000%. On SepNnber 3,1993, during eddy current testing of #3 steam generator tubes, Maine Yankee found 7 defective tube. in a 688 tubes sample. Plant Technical Specifications 4.10 requires reporting of this condition. The root cause of this event is considered to be general corrosion or corrosion cracking due to l
contaminants and stresses. The inspection sample as expanded to include all unplugged tubes in #3 steam generator.
All defective tubes were plugged.
i DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309.. 1993...... 0.19......... 0..... 9311020171...... 0...... 09./.28./.93..
i POWER LEVEL - 000%. On September 28,1993, while in a refueling outage, Maine Yankee determined that one of four available Service Water pumps (P-29A B.C.D) did not deliver sufficient flow capacity to meet the design basis accident analyses. Service Water flow tests were conducted on September 23, 1993 after installation and functional testing of new Service Water flow instrumentation. On September 28,1993, af ter analyzing the new data, it was determined that P-298 was degraded. P-29B was declared inoperable. The safety significance of this event is that at power, if train A (P-29A & P-29C) is lost during a design bases accident and one B train pump, P-290, was out of service, then only P-298 would be available to remove heat from the component cooling trains. P-29B is scheduled to be overhauled. The cause of the pump degradation will be determined from overhaul results.
l DOCKET YEAR LER NUMBER REVISION DCS NUMBER NS!C EVENT DATE 309. 1993..... 020 0
9
.................. 312020119.............. 0...... 10/.12./.9 3..
l POWER LEVEL - 002%. This infomational LER is submitted to doctrnent events related to a deviation from the Technical Specification requirements for entry into the Power Operation Condition (condition 1). On October 11,1993 while returning to power operations following a refueling outage, condition 7 was unintentionally wrtered prior to Technical Specification prerequisites for the condition being completed. Entry into the Power Opvating Condition (condition 7) is defined in the plant's Technical Specification as occurring when the reactor is critical and indicated power on the Power Range Nuclear Instrumentation (PRN!) exceeds 2%. At the ti=? of the event, operators were relying on Wide Range Nuclear Instrinnents for power level indication and they w9re not aware that Technical l
Specifications required that PRN! be used for detemining entry into the Power Operating Condition. Plant Technical l
Specifications also require the establishment of the three auxiliary and emergency feedwater flow paths prior to cntry into the power operating condition. Prior to establishnent of the final emergency feedwater flow path. 2%
power as indicated on the PRNI digital volt meter was exceeded. The cause of this event is a failure to recognize that plant procedures did not incorporate the technical specification definition of the power operating condition, In order to prevent recurrence, plant procedures have been revised to specify that PRN! shall be used to determine the 2% power point of entry into the Power Operating Londition. The need for providing additional guidance to operators concerning the power level indications to be observed through each segment of the operating range will also be evaluated.
B-7 l
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MAINE YANKEE - 1994 DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3.09... 1994......001........ 0..... 9 4 02.18 0188....... 0...... 0.1/.0$/ 94 I
POWER LEVEL - 100%. On January 13. 1992, and on February 12, 1992, with the plant in the power operating condition.
both trains of control room ventilation were made inoperable when panels were opened for f an maintenance. Opening i
the panels prevents effective isolation of both trains of control room ventilation by allowing a path for atmospheric air to enter. Plant Technical Specification 3.25.8 requires two trains of control room ventilation to be operable when the reactor is critical. Therefore the plant was in a condition prohibited by Technical Speci fications. The cause for this event appears to have been a failure to recognize how opening the panels i
affected the ventilation system and not having the activity classified as a cold shutdown activity. Planned maintenance activities requiring the removal of these panels have been scheduled for times when the plant is in cold shutdown.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3.09....1994......002........ 1.... 940706008.5......0...... 02/.07/.94 POWER LEVEL - 100%. This LER is being submitted to supply information related to inadequate configuration control in the design and operation of Maine Yankee's Steam Generator Blowdown System which resulted in operation of the plant in an unanalyzed condition. On December 3, 1993, Maine Yankee recognized that station design and a&linistrative controls did not prevent operation of the Steam Generator Blowdown System outside the bounds of Maine Yankee's transient analysis. Imediately following identification of this discrepancy, a&iinistrative controls were stablished to e sure conservaA operattan of the Blowdown System. At that time, Maine Yankee had detemined that the blowdown system was operated'in an unanalyzed condition, but that this condition did not significantly compromise plant safety. Further analysis of the situation revealed that the fluid conditions post trip may change such that more mass would be transported from the steam generators than was originally considered. Thus, on February 7, 1994. Maine Yankee determined that the Steam Generator Blowdown system had been operated in an unanalyzed condition which may have significantly af fected plant safety. Stricter adrninistrative controls were imediately set to limit full power blowdown flow rates. A thorough analysis of the safety consequences of this event has been completed. The analysis has concluded that the plant did not operate in an unsafe condition.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309....1994...... 003..........1.... 9407060.035...... 0...... 02/.22/94 POWER LEVEL - 100%. The Maine Yankee Service Water system provides cooling to the Component Cooling system which cool Emergency Core Cooling equipment. Maine Yankee's response to ci e9-13 included installing flow measurtng devices in the Service Water system and a review of Service Water CJrt tional Performance Inspr.ctions at other plants. Through this review, heat exchanger flow imbalance was identified as an issue. Further analysis of flow data collected at Maine Yankee revealed that the Service Water system is susceptible to flow imbaltnr.s-s due to heat exchanger inlet strainer differential pressures and design differences. The inlet strainer differential pressures lead to ficw imbalances which require an penalty in the system's safety analysis. As a result, on February 22, 1994, Maine Yankee concluded that, in the past, Service Water flow may not have met design basis requirements with warm river water temperatures. During the winter months the river water temperatures are low enough to provide sufficient cooling to the Component Cooling water heat exchangers. However, in the sumer, the river water tageratures rise above that required to sufficiently cool the Component Cooling Water heat exchangers under all design conditions. Thus, Maine Yankee may have operated the Service Water system outside its current design basis.
Maine Yankee is investigating several options to assure the Service Water system meets design requirements during sisnmer months including: improving the screening of the service water pug intake water, igrowing servire water pug performance, improving the flow Nasuring instrtsnentation, reviewing the design basis Calculations, and establishing heat exchanger differential pressure limits.
B-9
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309....1994...... 007.......... 0... 9406220406..................... 05/.17/94 0
POWER LEVEL - 100%. The Nuclear Safety Audit and Review Comittee (NSARC) and the Operations Department Manager requested Maine Yankee Quality Programs Department (NYQPD) to perform an audit of the completed Emergency Core Cooling System (ECCS) locked valve program. During the assessment MYQPD discovered that a one inch globe valve of an ECCS subsystem was not locked. The valve (SCC-18) was not in its proper ECCS position. An inline valve (SCC-19) serving the same function and adninistratively controlled by a class "A" procedure was shut but not locked.
Subsequently, SCC-19 was locked in lieu of SCC-18. The function of the valves were to isolate Secondary Component Cooling (SCC) water to the chemical addition tank in the SCC system. Maine Yankee Technical Specifications (Tech.
Specs.) requires manual ECCS valves (and subsystem valves) to be aligned and locked in the position required for safeguards operation. SCC-19 was imediately locked.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 306....1994...... 006......... 0.... 94 06220388.......0..... 05/.18./.94 POWER LEVEL - 100%. On May 18,1994, the reactor tripped from 100% power on loss of load due to a main turbine trip.
The main turbine tripped due to a trip of the turbine-driven feedwater pump (TDFP). The TDFP tripped on overspeed when high pressure (HP) steam was manually aligned to the TDFP. Earlier, an air leak on a 345 KV switchyard breaker required decreasing power to 600 MWE (70% rated pcwer) to allow breaker isolation. Reactor power was maintained at 100% while the main turbine load was being reduced. At 80% rated output, the main turbine extraction steam did not have sufficient pressure to run the TDFP and therefore HP steam had to be aligned. The control room recognized that the HP governor valve was cycling and dispat:hed an operator to open the HP isolation valve. Since the HP governor valve already had a high open demand signal, the pump tripped on overspeed. The root cause of the plant trip was inadequate procedural guidance. Changes have been made to the procedure to prevent recurrence. A more formal root cause evaluation may include recomendations to further enhance operating the pump under all conditions.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3.09....1994.......009........... 0..... 9408110294..................... 0.7/.03/.94 0
POWER LEVEL - 100%. On July 3, 1994 a review of the procedure, that alternates Spray Building Exhaust Ventilation Fans, indicated that both fans are off for a brief period of time during this evolution. Technical Specification (TS) 3.6 C.2 requires two operable and redundant ECCS trains during power operation. There are no specific TS associated with the fans. However, a Maine Yankee TS Interpretation concludes that Spray Building Exhaust Ventilation must be operable in order for LPSI and CS to be operable. $1nce both trains are affected by this action, entry into TS 3.0 A.2 is required. The time required to alternate the fans is so short that no shutdown is comenced. A similar event, both fans placed in the off position. has been reported by LER #93-010. Recent NRC interpretations concluded that entry into TS 3.0 A.? is reportable under 10 CFR 50.73. The cause of this event was en inappropriate procedure for alternating fans. A new section has been added to the procedure to change the sequencing so as to avoid this problem, i
DOCKET TEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3.09.. 1994...... 0.10......... 1.... 9.508.29.0028.......
0...... 07/.11/.94..
-1 POWER LEVEL - 100%. At 1250 on July 11, 1994, an Auxiliary Operator, while performing his normal rounds, noticed wires protruding from a conduit elbow in the Main Steam Valve House. Upon closer examination, he found that there was no fire barrier sealant material inside the conduit where it penetrated the wall into the adjacent Reactor MCC Room. He then noticed a second conduit with no fire barrier sealant material within it. Both conduits were part of i
a new installation for upgrading Non-Nuclear Safety wiring systens in the plant. The Auxiliary Operator called the Control Room and was directed to remain at the penetrations as a fire watch. The penetrations were then properly
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sealed with fire barrier sealant material. All penetrations which were part of that conduit installation were inspected to ensure that they were properly sealed. No further discrepancies were found.
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DOCKET YEAR LER NUMBER REVISION DCS NUMBER NS!C EVENT DATE 309... 1994
..........1S........ 0..... 94 09 060.162.......0..... 07/.24/.94 0
t POVER LEVEL - 000%. On July 24, 1994, with the plant in a Cold Shutdown Condition, operators were performing a survelliance on the Secondary Component Cooling (SCC) System Non-Safeguards ! solation Trip Valves. During the surveillance, it was discovered that one of the valves had failed open due to an apparent fault in the 2-out-of-2 trip logic circuitry to the solenoid operated valves (50V) controlling the actuating air to the isolation trip valve actuator. The purpose of these trip valves is to isolate non-safeguards, SCC cooling loads in the event of a postulated seismic event. At the thre the valve failed open, the SCC subsystem was required to be operable to provide cooling for Residual Heat Removal (RHR) Train B.
Investigation determined that the proximate root cause of this event was a faulty, redundant contact in the 3-position control switch for one train of the trip logic circuit; which in turn caused one 50V to de-energize and vent the actuating air required to hold the trip valve shut. The insiediate corrective action taken to restore the operability of the trip logic circuit was to perfors a temporary plant modification which installed a jumper around the faulty contact in the 3-position switch. The planned, long term corrective action is to replace the faulty, 3-position switch at the first opportunity.
e...................................................................
DOCKET YEAR LER NUMBER ' REVISION DCS NUMBER NSIC EVENT DATE 309....1994
..........16......... 1.... 9411040218...... 0...... 08/.04/.94 0
POWER LEVEL - 000%. At 1220, on August 4,1994 with the reactor in a cold shutdown condition, plant operators determined that the Emergency Feedwater isolation and regulating valves for #1 Steam Generator were leaking by.
Subsequently it was determined that under accident conditions which require isolation of Emergency Feedwater, valve leakage could exceed Safety Analysis assumptions. Maintenance activities were performed to reduce Emergency Feedwater valve leakage to within acceptable limits. In addition, adninistrative controls were implemented to ensure Emergency Feedwater leakage is niaintained within the bounds of Safety Analysis assumptions during accident conditions. A root cause investigation identified inadequate maintenance procedures, and inadequate post maintenance testing as the main causal factors for this event. The safety significance of this event was not initially known, therefore this event was originally reported under the provisions of 10CFR S0.73(a)(2)(ii)(A), an unanalyzed condition that significantly compromised plant safety. However, recently completed analyses show that plant safety was not significantly compromised by this event. Therefore, this event is now being reported for information only.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309... 199.4.......17 0............... 9411150243....... 0..... 10./.04/.94 0
POWER LEVEL - 100%. This is a voluntary report submitted for information only. While performing quarterly stroke testing of containment isolation valves, with the plant at 100% power, one of two Containment Safeguards Sump Suction Isolation valves failed to fully re-shut. This valve is a dual function Emergency Core Cooling System (ECCS) valve. It is normally closed to provide the single Containment Integrity (Cl) barrier between the safeguards sump and the suction piping for one train of safeguards pumps. During a Loss of Coolant Accident, this valve opens automatically upon receipt of a Recirculation Actuation Signal to provide the suction head to the safeguards pumps.
The valve was declared inoperable and the applicable Rewr.edial Actions of Technical Specifications (TS) were feelemented. The root cause of the failure (misalignment of the valve operating reach rod) was identified and corrected. Valve operability was restored within the allowable remedial action timeframes. A Management review of this event resulted in a reassessment of Manegement's existing guidance to operators when a single containment barrier valve becomes inoperable. Now, more conservative guidance, specific to the unique application of the Containment Safeguards Stanp suction Isolation Valves, will require operators to restore the Cl function of an inoperable stenp isolation valve within one hour; vice the four hours allowed by the TS.
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DOCKET YLAR LER NUMBER REVISION OCS NUMBER NSIC EVENT DATE 3 09....199. 5.....003..........1.... 9. 50804 019.7......0...... 03./ 02./ 9 5 POWER LEVEL - 000%. On March 2, 1995 at 1643 during a refueling outage, M ine Yankee determined the acceptance criteria for the refueling containment spray pump flow test met the literal wording of Tech Specs but did not meet the intent of Tech Specs. Maine Yankee has revised the surveillance procedure for testing the containment spray pumps to ensure the Intent of Tech Specs is met along with the literal wording. Test data recorded in June, 1995, indicates the pumps are capable of achieving the flow rates assumed in the safety analysis. Maine Yankee performed an internal design basis recovery effort on ECCS systems. An internal vertical audit on the containment spray system discovered the inconsistency in the acceptance criteria. Similar design basis recovery efforts were performed for HPSI and LPSI. PCC/ SCC have undergone system flow rate tests this refueling outage to ensure consistency with the safety analysis. SW is monitored while the system is in operation to ensure safety analysis flow rates are achieved. This issue has been addressed for all the ECCS systems.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309...199.5...... 04...........1.... 9508040237
(#
............... 3./. 04 /.9 5 0
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POWER LEVEL - 000%. On 4 March 1995, the plant was in a refueling shut down. Steam Generator (S/G) tube eddy current testing on the #2 $/G identified a 360 degree circumferential crack-like indication with an average through wall depth of 83%. Circumferential crack-like indications of an average through wall depth greater than 79% are considered degradation to a principal safety barrier On 10 March 1995, greater than 1% of #2 S/G tubes were determined to be defective, i.e.
crack-Itke indications or pits greater than 40% through wall depth. On 12 March 1995, a 360 degree circumferential crack-like indication with an average through wall depth of 81% was discovered on the #3 S/G. On 13 March 1995, greater than 1% of #3 S/G tubes were determined to be defective. On 19 March 1995.
greater than 1% of #1 $/G tubes were determined to be defs..tve. On 25 March 1995 eight additional tubes with circumferential crack-like indications of an average depth greater than 79% through wall were identified. Four tubes were in fl S/G and four tubes were in #3 S/G. All circumferential crack like indications of an average depth greater than 79% through wall were located in the hot leg of the tubesheet Expansion Transition Zone. An analysis of three pulled tubes confinned the circumferential crack-like indications were Primary Water Stress Corrosion Cracking. On May 11, 1995 Maine Yankee presented a plan to the NRC to sleeve and/or plug 100% of the tubes on the hot leg side. The sleeving program began ein 5 June 1995 and is expected to be complete by the end of the year.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309 1995 005 0
0
.................................. 9.504070205.................... 03/.06/.9.5 POWER LEVEL - 000%. On March 6, 1995 at 1125 during a refueling outage Maine Yankee discovered significant amounts of rust and scale in portions of the Tech Spec required Turbine Lube Oil Reservoirlprinkler t.d Seal Oil System Sprinkler systems. The rust and scale flakes were of sufficient size and quantity that they.a/ have plugged the flow orifices or spray nozzles. This may have rendered the systems inoperable during the last operating cycle. The Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler utilize Aqueous Film Forming Foam (AFFF) to more effectively extinguish oil fires. The AFFF is highly corrosive. The cause of this event is the improper flushing and draining af ter inadvertent actuations of the Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler, which allowed portions of the piping to corrode. The affected Turbine Lube Oil Reservoir Sprinkler and Seal Oil System Sprinkler piping has been cleaned or replaced and repitched. The three remaining foam deluge sprinkler systems will be disassembled, inspected and repaired as necessary. These three foam systems are not required by Tech Specs. A procedure will be developed by 12/31/95 to flush and dratn foam deluge systems following any system actuation.
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- O DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3 09... 19 9. 5..... 009.........0..... 9 50 7060.17 8.......0...... 03./.0.1/.9 5 POVER LEVEL - 000%. In March 1995 while the plant was shutdown for refueling, an engineer realized that the in-place testing of the control room recirculation ventilation filters did not account for bypass flow. This testing is required by Technical Specifications to be performed at least every refueling. The Maine Yankee engineer reviewed other Technical Specification required filter tests and found that the containment purge filter testing did not consider bypass flow. A subsequent NRC inspection revealed that the test contractor had notified Maine Yankee in a 1992 test report that bypass flow should be evaluated. Maine Yankee reviewed the design basis for both filters.
The analysis of the control room recirculation system shows that the filters would still function to protect the operators with up to 19% bypass of Technical Specfication required flow. The safety analyses for a fuel handling incident and other radiological incidents in containment do not take credit for the containment purge filters to meet 10 CFR 100 limits for off-site exposure. The plant is currently shutdown for sleeving repairs to the steam generators and will be returned to operation at the end of 1995. Prior tc returning to power operation, Maine Yankee will re-test both control room and containment filters, accounting for by-pass flow.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309 1995 0
..................10........................................../.26/9.5 0
9509250359 0
07 POWER LEVEL - 000%. Or. July 26, 1995 with the plant in a Ref.,eling Shutdown conditio9 with the fuel off-loaded, Maine Yankee determined that two motor operated valves in the Containment Spray system were susceptible to the pressure locking phenomena described in NRC Information Notice 95-18. It was postulated that under certain accident conditions, pressure locking of these valves could result in loss of containment spray during a small break LOCA.
Immediate actions included: Notification of plant operating personnel, notification of the NRC via the ENS, and initiation of an evaluation of the safety significance of the condition. Since the reactor core had been previously of f-loaded to the Spent Fuel Pool, imediate corrective actions were not needed. Maine Yankee will modify the two Containment Spray valves to prevent pressure locking prior to plant startup. LER 95-008, Potential Inability of HSI-M-54 and HSI-M-55 to Perform Their Safety Function, documents two other safety related valves with the same issue. No other nuclear safety related motor operated gate valves have been found to be susceptible to this phenomenum. Other gate valves potentially susceptible to this phenomenum, which may pose a significant personnel safety concern relative to integrity of the pressure boundary, have also been evaluated, with no additional concerns identified.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309..1995..... 0.11........ 0..... 95100703 70.....0...... 08./.03./.9.5 POWER LEVEL - 000%. THIS IS A VOLUNTARY LER. Maine Yankee is currently shutdown with the unit defueled. On August 3,1995, Emergency Feedwater Isolation Valves EFV-A-338, 339, and 340 were disassembled to verify proper disc orientation and seat placement. These three valves are 3 inch, Contromatics, butterfly, 600f, with teflon seats rings, Upon inspection of EFV-A-338, it was discovered that a section of its teflon seat ring was damaged, creating a slight gap between the valve seat and disc over an arc of about one inch in length. An evaluation of the potential leakage resulting from this degradation was initiated. Maine Yankee has determined that the potential leakage is bounded by the asswned seat leakage in the Emergency Feedwater Isolation valve Safety Analysis. The cause of the EFV-A-338, 339 and 340 seat ring damage has been attributed to excessive crush of the seat ring due to tolerance stack-up of mating parts. The subject valves will be modified, as recorenended by the vendor, by machining the seat retainers such that the proper assenbly tolerances can be obtained.
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0..... 9512060117...... 0.......11/01/.95 POWER LEVEL - 000%. On November 1. 1995, Maine Yankee was in a Refueltng Operations Condition with approximately j
one-third of the fuel in the reactor and two-thirds in the spent fuel pool. At approximately 0*00, the control room operator (CRO) connenced performance of the daily radiation monitoring system (RMS) operation test. After completing the procedure, the CR0 lef t the containment (CTMT) purge valve r. ode selection switches in the "on-line" position, rather than restoring them to the " refueling" position. The " refueling" position is used while moving fuel or core components and the "on-line" position is used when in the remaining plant conditions. The manipulator crane and the CTMT low range RMS monitors trip the CTMT purge valves shut when they receive a signal, with the switch in " refueling" position. In the "on-line" position, the primary vent stack and CTMT gas monitors trip the valves. The dayshift CR0 found the switches mispositioned during routine shiftly checks (eight and one-half hours later), after fuel movement had occurred, and reported the mistake to his supervisor. Refueling operations was placed on manageme 4 hold, until a root cause evaluation could be performed. The safety significance of this event is that the valves would not have closed on the required high radiation signal during a fuel handl.ng incident. The time period of 0.5 hrs, allowed by technical specifications for placing the switch in the "on-line" position for testing the radiation monitors, was exceeded. The corrective actions included: (1) adding a sign-off step to verify the switches have been positioned correctly with a second verification (2) discipline the individual involved, and (3) performing a root cause for further improvements relating to human performance.
DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 309......1995.......
0.17.........
0...... 512110309......................1 1/. 0 6/.9 5 9
0 POWER LEVEL - 000%. On November 6, 1995, Maine Yankee was in a Refueling Operations Condition with core relrad in progress. While working in the Containment Spray Building, an operator noticed a 1-2 drop /second leak at Tweld on 3/4 inch piping upstream of a safety valve in the Low Pressure Safety injection / Residual Heat Removal system.
Initial evaluation of this Condition resulted in a determination that Residual Heat Removal system operability was not compromised. However, following disassembly and further inspection it was determined that a circumferential linear crack of sufficient magnitude to potentially impact system operability was present in the weld. The affected joint has been cut out and rewelded. A causal factors investigation identified a fabrication anomaly and vibration induced fatigue as causal factors for this condition.
MAINE YANKEE - 1996 DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 3.09...1996..... 001........ 0.... 9602.120268.......0..... 01/.10/.96 POWER LEVEL - 000%. On 1/10/96 Maine Yankee was in a Mot Shutdown Condition during plant startup when the Low Pressure Safety Injection Pumps and Containment Spray Pumps were declared inoperable due to less than the design ventilation flow rate. The outside air suction flow path to the Spray Building was partially blocked by a leak from an overhead heating coil that saturated and froze the paper inlet filters. The ice was removed and the pumps were declared operable 63 minutes after discovery of the partial blockage. Maine Yankee corrective actions were: (1) removed the ice blockage, (2) increased the monitoring of this flow path for blockage and (3) evaluate a design modification to prevent an ice buildup.
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ENCLOSURE 3 ur e
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,s UNITED STATES p
E NUCLEAR REGULATORY COMMISSION f
WASHINGTON, D.C. 20555-4001
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June 26, 1996
[I MEMORANDUM TO:
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MWOffice,L. Jbrdan, Director FROM:
f r Analysis and Evaluation of rational Data SU6 JECT:
AE00 PROCEDURE NO. 21, NRC INDEPENDENT SAFETY ASSESSMENT (ADAPTATION OF E 8.7)
Attached is AE00 Procedure No. 21, NRC Independent Safety Assessment (Adaptation of MD 8.7). A revised Table of Contents is also attached.
When additional procedures are developed, they will be distributed to you.
Attachments:
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i 15
Handbook M
f(ISA)] 01:gn:: tic reclu:tien Teane This part sets forth the composition of the 01:;n;;ti
- vslucti:n g Team (Or) and outlines its activities in performing a diagnostic evaluation.
Objectives of @ 01:;n;; tic recluati:n "'::: (A)
To conduct an independent, multidisciplined, safsty e
p t p :f;rsen : b ::d cycluati:n of MaissiIIKankes li; n :f r ::t:r f: ilitic: in response to EDO sasignment
@ direction hfjthe[Cthiiirman. (1)
To evaluate the adequacy of licensee performance related to e
activities that may affect the public health and safety. (2)
To document the evaluation results that identify licensee e
strengths and weaknesses in a formal report, placing emphasis on lRi[gghd{o]tliby1((M]@MM15 g root cause determination of performance problems. (3)
To provide sufficient information to characterize the e
current plant safety performance and the capability of existing licensee programs to improve safety performance.
y I
~
t 4
I i
1 This information combined with existing information forms I
the basis for NRC regulatory decisions regarding the regulatory programs for the reactor facility.
I (4) 1 i
j Scope of the M Oingn:: tic Pielucti n (B) 1 1
{
The j! f'Y N $ '. f 500 will approve the areas to be evaluated at i
the selected reactor facility. The 0"" : n ger : -/ r Ji:0 the t
scope and areas of emphasis of the evaluation miy[bsjysViisd based on initial findings. Evaluations may include a j
comprehensive review of en: er ::r: Of the following areas: (1) 4 5
1 j
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M.
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echn..i.<# w...1,7w..w.--,suppS.rti.li.,*<.. u16. d_i.r.w wf. -we-g m. o. d.._i'f_iwu scatiw< ww w. :<
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b-The conduct of plant operations (including simulator drills e
or walkthroughs of operating and emergency procedures, as appropriate) and training effectiveness. $$ fe)-
Management involvement an# effectiveness in the oversight e
2 4
.M
9 and control of plant safety performance (including corrective actions, quality assurance, quality control, and safety committees). }d{ fbF Management and organizational approach to safety including e
prioritization, planning, staffing, and communications. (({
i+F 5;; int: ring t :hni 01 : pp;rt including ::dific ti:n:,
t-. rcry ch ng::, ::nfigur ti:n ::ntr:1, d::ign d:::::nt:tien, and Operability d:t:r=incti:nc. (d)
Plant maintenance and testing (including surveillance, post-e maintenance, and post-modification testing). This may include material condition of the facility, including balance-of-plant areas with respect to concerns such as radiological restrictions on accessibility of equipment, frequency of challenges to operating personnel and plant safety systems, and complications in the plant response to off-norma 1 conditions. [(j)] fet i
An engineering review of system functional capability based j
e on review of a particular system or systems and/or review of modifications made by the licensee. [j)] f4F Apparent weaknesses in safeguards, emergency preparedness, e
3
and health physics 'M M i @ ~@ $ R M i[fj @
m~Tdhi :: indi :t:d by ::: tin: in:;::t12:
- rle :: :: r g ::t d by ""O :::i : :.::;::: t.
(g) 1 Assessments of repetitive or significant failures of l
e important systems and equipment. ((1)] fht l
l Strengths and weaknesses in safety performance will be identified, where found. Emphasis will be on root cause determinations for safety performance weaknesses and significant problem areas identified. The adequacy and effectiveness of 3
license % safety 4 provement programs will be evaluated. (2) l Safety issues of immediate concern will be promptly communicated to NRC regional managementif(WRRy and brought to the licensee's attention. The W BIFP will support the region gig as appropriate to ensure prompt resolution. Subsequent followup is the regional office's responsibility. (3)
NM@IFA 4
M l
The identification of noncompliance with NRC requirements is not the focus of these evaluations. Information substantiating 1
identified noncompliances will be collected and provided to the i
I i
4 l
l
4 1
1 l
l regional office to support subsequent enforcement action the
]t regional office deems necessary. {JJ -(4)
)
i j
Evaluation Schedule (C) i 1
1
- 3
-::::ti = p;;;.11; in
- p; nt-
.., 4 3
2 l
- i!10
- hrful. i
- ;;;;r:1 prt: tic:
-d f;r pi nning i
- -_g
- ::, : ding ::ti: :=l :ti:n will consist of: (1) two weeks of onsite evaluation; (2) -@-.,ene week [ at the NRC headquarters 1
office to review findings and adjust plans; and (3) ti.i.m.wiii one weekiji 4
w.w vm i
4 (as required) of followup onsite effort to complete the 1
1 evaluation.,"7pi= lip-4 The four weeks prior to the-initial w j
j onsite evaluation will be allocated for team preparation. The target date for submitting the evaluation report to the f
M ""^ ;:::::lly is g g etw weeks after the completion j
l of the follow-on onsite evaluation period. An exit meeting with j
top-level licensee management on evaluation findings will in held after the onsite evaluation is completed and following the j
briefing of M J; @ NRC senior management.
f l
i g 959 Management and Composition (D) i i
The BBW-manager is an SES-level manager who has i
j direct responsibility for and control of the g ese4gned j
i dit; ::ti: ;.cir:ti:n. The M BB9-eenager reports to 4
the Director, ABOD. The s!,)ecific responsibilities of the g g i
1 l
5
l.
95EHaenager are to: (1)
Prepare the M 3XB1771Md cit:
if1: Dicen :ti; o
0;;1;; tic: "l:= and submit it to the Directore of AEOD and
, :_.' th:
- grict
- "
- ;;ien
- 1.'_'-ini:tr:ter, for review and
': - eenouecenee. (a)
Direct en4-manage the g DIFP during the evaluation process e
and ensure that the objectives and schedules of the evaluation plan are met. (b)
Promptly communicate immediate safety issues to the region e
and licensee so they may be appropriately addressed. (c) e Make recommendations to the Director, AEOD, regarding any additional resources needed (e.g., additional team members, consultants, contractor assistance) to fulfill the scope of 8
the evaluation. (d)
- t.
Evaluate g DirP findings in a timely manner and keep the e
Director, AEOD, informed of M 989 progress and findings.
(e)
Interact with NRC offices and other organizations ao e
required during the course of the evaluation process g,
mtfmN"MHREiiiniliisiiltaGGii. (f) j i
I 6
l
.m.
4 4
serve as the spokesperson for {$ BIPP activities in e
interacting with the licensee on significant matters i
i involving the evaluation g ttjpl g ] g g g g g g g. (g) i Provide regular briefings for the licensee to ensure that e
g 959 factual findings and concerns are understood by the licensee. (h) i i
Brief the Eksm&#EsafjadjyM;siti}yjfthEEEDW,$3Rn[siiiklRI 4
e i
Oir;;t:r;, " "^0 :nd !"*, th: 0:gien:1 Administrator, nd the i
BDO on ISA BEPP findings and conclusions and make i
j recommendations for NRC staff followup actions. (i) i Prepare the $ BIFP report, the report transmittal letter to j
e the licensee, and the NRC staff action memorandum to NRC j
l program offices and the Regional Office and submit them to I
i the Director, AEOD. (j)
Prepare and participate in the exit meeting with top level e
licensee management. (k) e Document and brief the Director, AEOD, and other NRC personnel as appropriate on the lessons learned from the g esp process and procedures following the completion of the evaluation. (1) 7
1 The membership and composition of t..ii4.wMV.'?Y 1 8.A : 0"" n: : lly will V vyN
%anya[
j M be drawn from the approved roster of potential DET managers and members and will depend on the assigned facility, its status, and the nature of the evaluation. The g BiFP will include a core of Diagnostic Evaluation #6-1himi$n @.-..s._-,l, i
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- p;ri:n :f l'"O t:25.nic:1 :t:ff r:riere and contractorsy [
-14
- ppr:prict. In 11 :::::, t The Ilif BIFP manager and team members selected will not have had recent significant involvesent in the licensing, inspection, or enforcement activities at the facility to rece2Ve the Id'9E. In cddition, t The resident inspector (s) should be used as technical consultant (s) to the ISA DEFP. KSA BIPP members will report to the ISA'[tfeamIfniiidsf OE" :,negee during the
@ di gn;;ti ev:luction period. (2)
Conduct of IS& Di gn;;ti OJ lusti:n (E) b e
The[ 6" vnlustion process includes observations of plant
~ ' ' ~ ~ ^ ~
activities, in-depth technical reviews, employee interviews, hardware walkdowns, and programmatic reviews in functional areas.
......... _ _.., _,. _,,. s u_._. u.
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Team Report (F) l i
The Director, AEOD, will approve the I_$n M report for submittal to the
" " "... " '... ^^^.. '.. '.... '... '..,..... '.. -
^*
a_._____2a._._,
, _ a &.._. _ &._ a L.._.
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.2_,_
s, l
predecisional until the M, BDO approves the report for transmittal to the licensee and forwarding to the Public Document l
Room. g 44)-
I 9
.. - - -.. _ =
t l
The g 959 report will address the major functional areas i
evaluated and will provide findings and conclusions regarding safety performance.' ]gj -(+)-
l The g M report will include identified strengths and weaknesses and the root cause(s) of safety performance deficiencies. g -(4-).
1 The g M report content will be controlled to provide only the detail necessary to support the findings and root cause determinations. N -(4-)-
l M Oic;n::ti: SJ:lucti:n Followup Actions (G)
The M M manager will provide and discuss, as appropriate, proposed staff followup actions resulting from Inn m findings j
\\
and conclusions as part of the final briefings of @ M l
S NRC senior management. The. 3 2 Regiona'l Administrator and Directore, NRR and-ABGB, will also provide input to the staff followup actions at these briefings. 20::d n th: briefing dicr::i;=, 2.: t r
- r vill d
- r:nt th: ::: - : d:d :t:ff 2di:n 0;r : ci 2-2 ::- :nt bj th n ;i ::1.id-ini tr:t:r, th:
Di: 2:r f ?TC, z.-i Di:::t :: :f : 2.:: :ifi::: =h::: =t ff 2dirr ::: M ing
- f. The agreed upon staff actions will be forwarded to the EDO by the Director, AEOD, for review. The EDO shall then assign NRC office responsibility for generic and l
i 10
plant-specific staff actions resulting from the evaluation that 3
warrant additional attention or action. The assigned Regional Administrator and Office Directors will provide a written status report (s) to the EDO with a copy to the Director, AEOD, on the a
disposition of staff actions. The Director, AEOD, will maintain a l
status of the staff actions involving generic issues. The status of these issues will be compiled in the AEOD Annual Report.
i i
e 1
i l
i l-11
4 i
i TABLE OF CONTENTS l
Procedure No.
Title Revised Date a
I Signature and Concurrence on Memos-and Letters 07/26/95 Outside AE00 i
2 Background Information for Commission Visits j
j 3
Screening of U.S. Operational Experience 07/30/95 3.1 Screening of Foreign Operational Data 3.2 Screening of Reactor Safeguards Information 3.3 Screening of Operational Data and Information -
j Nonreactor Reports l
,4 Pr aration of AE00 Technical Reports
)
5 Recommendation Tracking System
\\
6 AE00 Funds Management 07/21/93 7
Periodic Information Reports i
8 Reporting Operational Experience to the Nuclear l
Energy Agency (NEA) Incident Reporting System (IRS) 9 Contacts with Members of Congressional Staff or News Media Representatives 10 Regulatory Information Tracking System (RITS) 02/12/95 11 Monitoring of Plant Specific Backfitting 12 Incident Investigation Team Administrative Requirements 13 Addressing Staff Concerns 14 Limited INES Implementation 15 Telephone Recording Device Operation 16 Recommending Third Party Assistance to Licensees
=
l s l Procedure No.
Title Revised Date 17 Monitoring and Assessment of Resolution of 07/13/94 Incident Investigation Team Staff Actions 18 AE00 Headquarters Office Selection Process 12/20/94 l
l 19 Review and Approval of Procedures for Incident l
Response
l 20 Guidance for the Acquisition of Federal Information Processing (FIP) Resources 21 NRC Independer.t Safety Assessment (Adaptation of MD 8.7) l l
i l
t i
I 1
!