IR 05000220/1989005
| ML17056A038 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 06/01/1989 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17056A036 | List: |
| References | |
| 50-220-89-05, 50-220-89-5, 50-410-89-05, 50-410-89-5, IEIN-87-004, IEIN-87-4, NUDOCS 8906140313 | |
| Download: ML17056A038 (46) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
Docket No.
License No.
Licensee:
89-05/89-05 50-220/50-410 DPR-63/NPF-69 Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Faci l ity:
Location:
Dates:
Inspectors:
Approved by:
Nine Mile Point, Units 1 and
Scriba, New York 4/4/89 through 5/12/89 W. A. Cook, Senior Resident Inspector R.
R.
Temps, Resident Inspector R. A. Laura, Resident Inspector M. Banerjee, Project Engineer R. Barkley, Reactor Engineer V. McCree, Project Manager, NRR M I)
R. Joh son, Chief, Reactor Projects Section 2C, DRP
~(i]sq Date Ins ection Summar activities including Unit 1 refueling outage progress and Unit 2 power operations, licensee action on previously identified items, plant tours, safety system walk-downs, surveillance testing reviews, maintenance reviews, NRC Bulletin and Notice reviews, and LER reviews.
This inspection involved 314 hours0.00363 days <br />0.0872 hours <br />5.191799e-4 weeks <br />1.19477e-4 months <br /> by the inspectors which included
hours of regular backshift inspection coverage and 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of deep backshift inspection coverage on April 8, 9, 15 and 23.
Results:
A violation of Unit 2 Technical Specifications regarding the minimum number of operable Main Steam Line Radiation Monitors is discussed in Section 1.2.a.
A second Unit 2 violation of 10 CFR 50.59 regarding the High Pressure Core Spray system is discussed in Section 1.2.e.
A Unit 1 licensee identified non-cited violation (NCV) concerning a violation of Technical Specifications for fire detection surveillances is discussed in Section 1. l.a.
Two Unit 2 scrams that occurred during this= period are discussed in sections 1.2.b and 1.2.cd A potential Unit 2 violation (unresolved item) regarding a high radia-tion area door found unlocked is discussed in Section 1.2.d.
8906140313 890606 PDR ADOCK 05000220 G
~
PNU
DETAILS 1.
Review of Plant Events (71710, 71707, 93702, 90712)
1.1 UNIT
The unit remained in cold shutdown with the core off-loaded during this inspection period.
On March 3, 1989, the licensee determined that they had not met the Technical Specification (TS) surveillance requirement for testing the Fire Detection System.
As a result of an annual fire protection audit conducted by the licensee's Safety Review and Audit Board (SRAB) and the NMPC Quality Assurance Department, a potential TS noncompliance was identified to the Fire Department for resolution.
The Fire Department then determined on March
that the SRAB audit finding was valid.
TS 3.6.6 identifies detection zones where fire detectors are required and specifies the number of detectors in each zone.
S'ection 4.6.6 states that each detector shall be tested by per-formance of an instrument channel test every six months.
Fire Department procedure Nl-FST-FPM-SA001 is used to perform the TS required testing.
However, the procedure was deficient in that it tests only 15 detectors in detection zone DA-4076E, -whereas the TS require 16 detectors.
Therefore, in testing conducted in December 1988, one of the TS required detectors was not tested.
Additionally, review of the procedure indicated three other zones with less than the TS listed number of detectors being tested.
However, these zones were successfully tested in December 1988 despite the procedure..
The root cause of this event, as stated in Licensee Event Report (LER) 89-04, was procedural deficiency as a result of personnel error in that the procedure was not accurately compared to TSs to verify that the proper number of fire detectors were being tested.
Procedure Nl-FST-SA1, Rev 4, was superseded by Nl-FST-FPM-SA001 in September 1987.
The original procedure con-tained all of-the TS required fire detectors, but the superseding procedure did not as a result of personnel error.
The inspectors have reviewed licensee actions taken to date and will monitor the planned corrective actions stated in LER 89-04.
In accordance with the provisions of the Enforcement Policy Guidance of 10CFR2, Appendix C, Section V.6, this TS violation is not being cited.
(50-220/89-05-01)
1.2 UNIT 2 The unit operated at full power during the majority of the inspection period.
Two scrams occurred during this period.
On April 5, 1989, the licensee declared the A Hain Steam Line Radiation Monitor (NSLRN) inoperable.
With the A MSLRN inoper-able, a half scram and half isolation were inserted on Division 1 as required by TS 3.3. 1.a.
Operating data is recorded on the HSLRMs each shift per Procedure N2-OSP-LOG-S001.
This procedure contains criteria to assess if the monitors are tracking properly and therefore functionally operable.
To support the performance of Procedure N2-ISP-NMS-WQ007 (weekly APRN surveillance checks),
the half scram inserted due to the A
NSLRM was bypassed for the duration of the surveillance test and then reset.
This. action was performed under TS 3.3. 1-1 note (a)
which requires the other Division I NSLRYi (C) to be operable in order to bypass the trip function on the A monitor.
These weekly APRN checks were completed on the evening shift of April 6.
While conducting routine shift checks following the completion of the APRN surveillance testing, the evening shift operating crew found that C NSLRN was reading out of specification which rendered it inoperable.
Review of the previous shift data'evealed the C NSLRN was also out of specification (inoperable)
during the APRH surveillance checks performed earlier in the shift.
This condition was contrary to the requirements of TS 3.3. l.a since there were no operable channels in the Division 1 Trip System.
Licensee investigation found the operator N/A'd the acceptance criteria check of the MSLRN data, in error.
A contributing factor was a lack of procedural clarity.
Further-more, the Assistant Station Shift Supervisor (ASSS)
who was responsible for reviewing the previous shift check data failed to identify the discrepancy.
The inspector was concerned that a
more thorough review of the shift check data could have identi-fied this error and precluded the problem.
As stated in LER 89-13, dated May 5, 1989, a trip signal from radiation monitors 8 or D (Division 2) would have resulted in a closure of the MSIVs as well as a reactor trip since the Division I Main Steam Isolation Valve (MSIY) isolation signal to the Reactor Protection System (RPS) associated with the "A" radiation monitor was not cleared during the APRM surveillance and therefore the safety function was available.
In that both channels of the Division 1 main steam line radiation monitoring reactor protection system were inoperable and the appropriate T.S. 3.3. 1.a action statements were not adhered to to place the Division 1 Trip System in the tripped condition, this is a violation.
(50-410/89-05-01).
On April 13 at 11:Ol a.m.,
a reactor scram occurred from 100'<
power due to an electrical fault in the generator protection monitoring circuit.
The electrical fault was determined to be caused by a loose lead in the generator potential transformer ground protection circuit which caused a turbine trip and subse-quent reactor scram (no generator ground occurred).
The loose lead was determined to have been caused by the retaining nut vibrating off of the terminal.
Technicians found the nut in the base of the cabinet.
Following the reactor scram, electrical power was automatically transferred from the unit transformer to the offsite power reserve transformers.
However, the 13.8 KY supply breaker to non-vital bus No.
3 (2NPS-SWG003) failed to close, resulting in a partial loss of offsite power.
The licensee determined that the 13.8 KV supply breaker (GEK-7347 Magne Blast Circuit Breaker, with a type ML-13 operating mechanism)
failed to close because the horizontal safety interlock roller arm on the operating mechanism did not rotate completely to engage micro switches for the transfer logic.
The licensee concluded that the roller arm did not engage the micro switches because of insufficient lubri-cation and a small amount of dirt on the mechanical linkages.
Following cleanipg, lubricating and exercising of the mechanism, the mechanical binding could not be duplicated.
The inspector determined that all similar GEK-7347 13.8 KV and 4160V breakers were inspected and no additional discrepancies were noted.
Oue to the loss of power to 2NPS-SWG003, the two operating feed-water pumps were deenergized resulting in a loss of feedwater flow to the reactor vessel.
When LOLO vessel level was achieved, both the high pressure core spray (HPCS)
and reactor core isola-tion cooling (RCIC) systems automatically initiated to restore level.
Operators subsequently stabilized vessel level and pressure using the condensate booster pumps and the steam con-densing mode of the residual heat removal system.
The inspector determined that the loss of both feedwater pumps could have been averted had the licensee realigned the power supply of the C
main feedwater pump (MFP) to non-vital bus No.
1 (2NPS-SWG001).
The C MFP has the capability to be powered from either non-vital switchgear for enhanced reliability.
Numerous MFP stop and starts and realignments were made prior to the April 13 scram due to various pump problems.
The operating crews did not ensure a more reliable configuration was finally established.
Procedure changes were subsequently made to caution operators against making a similar mistake in the future.
The inspectors reviewed the licensee's corrective actions and attended the post-trip SORC review meeting held on April 15, 1989.
Inspector questions regarding the operator actions, plant response and corrective actions were adequately addresse On April 22, at 7:42 p.m.
the Unit 2 reactor scrammed on high Average Power Range Monitor (APRMs) power as a result of a pressure transient induced by the Electro-Hydraulic Control (EHC)
system.
At the time of the event, control room operators, in conjunction with an operator at the local EHC control cabinet, were performing a weekly surveillance test of the turbine backup overspeed trip function.
This test, performed in accordance with Section F.3.0 of procedure N2-0P-21, is designed to check electrical circuitry only, and is performed locally at the EHC control cabinet by simply depressing a pushbutton (BACKUP OVER-SPEEO TRIP -
PUSH TO TEST) unti 1 a light comes on, at which time the pushbutton is released.
Subsequent licensee investigation revealed that at the time the operator depressed the pushbutton to perform the test, he also informed the control room personnel of his action via a hand-held two-way radio, or walkie-talkie.
The operator was not aware, or did not remember, that the EHC control circuits are sensitive to radio transmissions.
Therefore, when he performed the test and informed the control room via his walkie-talkie, the radio interference caused a disturbance in the EHC circuits which caused the turbine control valves to shut which induced a pressure increase and caused the reactor power to increase to the scram setpoint.
Two concerns from this event were identified.
The operator at the local control panel failed to notice a sign on the end of the EHC control cabinet which cautions against the use of walkie-talkies in the vicinity of the equipment.
This situation was remedied by the placement of large, "attention getting" signs posted at the doors for access to all rooms which contain radio-sensitive equipment.
The second concern involves the lack of sensitivity on the part of some plant personnel to the radio-sensitive nature of some equipment in the plant.
The control room operators should have been knowledgeable enough to be concerned that the operator at the local EHC panel was using a walkie-talkie to communicate with them.
In addition, licensed operators and non-licensed station personnel apparently did not receive any classroom or on-the-job training concerning the sensitivity of certain station equipment to radio transmissions.
The inspectors will review licensee corrective actions in this are d.
On May 5, the licensee initiated a 50.73 notification that a
locked high radiation area was found unlocked with the door (Gate TB 250-18) ajar.
The licensee immediately secured the area and confirmed that the dose rates were above the 1000 mr/hr limit for locked high radiation areas.
The licensee is conducting an investigation to determine the root cause.
This item will remain unresolved pending review of the licensee's investigation.
UNRESOLVED item (50-410/89-05-02).
On May ll, during a safety system verification, the inspector noted the HPCS "keep fill"pump was tagged out for maintenance and the HPCS system was not declared. inoperable.
When brought to licensee management attention for consideration, the HPCS system was declared inoperable and the applicable TS Action Statement was entered.
Maintaining the HPCS system'perable with the "keep fill"pump inoperable, is not in accordance with the HPCS operating procedure, the annunciatqr response procedures, the FSAR and contradicts the inspectors'nderstanding of the TS operability requirements.
Discussions with the Station Shift Supervisor (SSS)
who tagged out the "keep fill",pump found he made a conscious decision to keep the HPCS operable since an alternate method was available to ensure the discharge side of the HPCS pump, remains full of water.
The inspector noted that although this alternate method may be a viable substitute, it is not recognized as a substitute in any of the above procedures and was not formally evaluated by a
TS interpretation or 10 CFR 50.59 process.
The ins'pector has summarized four concerns to be addressed by the licensee:
A non-conservative interpretation of the HPCS system oper-abilityy requirements v as made without a formal evaluation to support it The alternate keep fill method was taken credit for, but not recognized by the Operating Procedure The licensee was unaware of the basis for the 65 psig mini-mum keep fill pressure recommended in the HPCS operating procedure for the HPCS discharge piping, and The Unit 2 Station Superintendent issued a directive dated January 9,
1989 that defined the process for how non-routine evaluations concerning operability determinations should be made.
This directive was apparently not sufficien'tly promulgated or not adhered t C The failure of the licensee to perform a proper safety evalua-tion, in advance, to determine if the removal from service of the HPCS keep fi11 pump adversely impacted the operability of the HPCS system, as described in the FSAR Section 6.3.2.2.5, or presented an unreviewed safety question, is a violation of 10 CFR 50.59.
VIOLATION 50-410/89-05-03.
f.
Procedure N2-IMP-GENQ029 (Pre-startup Valve Lineup Check) per-formed on January 21, 1989 revealed that seven drywell pressure transmitters were found improperly isolated.
This procedure is performed following an outage at the discretion of Instrumenta-tion and Controls ( I&C) Supervisor."
The licensee determined that transmitter isolation valves should have been open Vice shut and sealed open during the last performance of procedure N2-ISP-ISC-R003 (reactor instrument line excess flow check valve operational testing)
on October 31 and November 6, 1988.
The licensee conducted an investigation to determine the root cause for these valves found out'f their required position.
The licensee determined that independent verification of valve positions was made improperly.
The technician who initially positioned the valves performed the independent verification, as well.
This is contrary to station procedural compliance guidance.
A second technician involved with the test (who should have per-formed the independent verification) was aware of this willful contradiction of procedural requirements, but took no remedial actions.
The test director of the surveillance was in the con-trol room for the duration of the test and was not aware of the improper valve position verification.
. The licensee took the following corrective actions:
Reperformed a valve lineup per Procedure N2-IMP-GENQ029 on 3/2/89 and 3/25/89, with no errors identified.
Conducted valve lineup checks on all other transmitters not covered by Procedure N2-IMP-GENQ029.
Category one transmitters not specifically addressed by current procedures were independently verified per MR156947.
Disciplinary action was taken against the three individuals involved.
Site-wide training was conducted to ensure proper procedural complianc In the shutdown condition, these detectors were not required to be operable and thus the immediate safety significance was mini-mal.
The inspector concluded that proper corrective actions were taken to assure that instrumentation was properly lined up for plant operation.
This item will remain unresolved pending additional NRC review of the details of this issue.
UNRESOLVED 50-410/89-05-04.
2.
Followu on Previous Identified Items (92700, 92702, 92703)
2. 1 Unit (Closed)
Unresolved Item (50-220/88-19-01):
This item remained open pending NRC review of the licensee's evaluation of high temperatures in the upper drywell with respect to the equipment qualification (Eg) aging factor on electrical equipment.
The inspector reviewed the Problem Report (PR) which was written as a result of the concerns identified in inspection report 50-220/88-19.
PR 874 concluded that drywell equipment in the Eg Program was not significantly impacted by the temporary high drywell temperatures which occurred during the summer of 1987.
Further, the Eg engineering group maintains cognizance of the effects of temperature variants in accordance with the Eg ambient, temperature monitoring program.
This item is closed.
(Closed)
Inspector Followup Item (50-220/88-26-06 and 50-410/
88-25-06):
Notification of State and local authorities via the RECS following declaration of an Alert classification exceeded 15 minutes.
The licensee issued Occurrence Report 89-17 on the noted deficiency which recommended that this item be addressed in future emergency preparedness training and that a review of notification procedures be conducted to streamline the process.
This action was completed and this item is closed.
C.
(Closed)
Inspector Followup Item (50-220/88-26-04 and 50-410/
88-25-04):
Information contained in press releases was not con" firmed prior to distribution since one release.incorrectly indi-cated a fire was burning in the offgas building.
The licensee determined that this finding was not totally correct in that at the time of the press release, a fire was suspected to be burning in the offgas building. It was later determined that this fire had not occurred; however, a followup press release to clarify this point was not made.
To avoid a recurrence of this event, the licensee committed to include instructions in the Corporate Emergency Response/Recovery Plan Implementing Procedure CPP-6,
"Public Affairs and Corporate Communications Emergency Communi-cation Procedure" to ensure proper verification of information and to provide for followup press releases to correct misinfor-mation.
This item is close (Closed) Violation (50-220/86-17-07):
Thi s item documented that administrative controls i,n Administrative Procedure (AP) 5.0,
"Procedure for Repair",
were inadequate or in some cases not followed for the performance of Mork Request (MR) 102?75 con-cerning maintenance on hydraulic control unit.
Changes made to AP-5.0 in revision 7 (effective August 23, 1986) require approval of an SRO for all WRs and provide guidance for determination of post-maintenance testing.
In addition, the licensee revised AP-5.0 to require a change to, or a different WR, when the scope of work changes.
This item is closed.
(Closed)
Unresolved Item (50-220/86-26-02):
Inspection Report 86-26 identified failure of corporate Engineering Staff,to com-municate the discovery of an inoperable component to Operations Department personnel.
Nuclear Engineering and Licensing proced-ure (NEL) 029, revision 2, incorporated a requirement to generate an Occurrence Report upon discovery of an inoperable safety-related component or a failure to comply with Technical Specifications.
However, NEL-029 only provides guidance for 10 CFR 21 reporting and does not address general failures such as ISI rejects or age related failures.
Discussions with licensee representatives determined that revisions would be made to NEL-029 to insure corporate Engineering personnel immediately notify site Operations personnel upon discovery of an inoperable component or failure to comply with Technical Specifications.
In addition, broader corrective actions have been initiated via the Unit 1 Restart
Action Plan to ensure timely notification of the Operations Department of any known deficiency which may impact a safety system or'omponent.
This item is closed.
(Open) Unresolved Item (50-220/88-80-01):
Timely completion and adequacy of licensee's action in closing out, NRC Notices and industry information.
A large backlog of implementation of industry experience related items in NRC Notices, INPO SOERs and SERs, GE SILs, etc.
were a concern.
The licensee's Nuclear Improvement Program addresses improved use of industry experi-ence as an action
~tern.
The inspector discussed the licensee's program for reducing this backlog with the Operational Events Assessment (OEA) Supervisor.
The OEA Supervisor described their improved program and increased staffing.
OEA has the overall responsibility for reviewing industry experience for applicabil-ity to Nine Nile Point and determining the needed corrective action.
OEA currently performs this responsibility with 21 con-tracted and three NMPC engineers.
The implementation of the needed corrective action is the responsibility of applicable line organizations and is tracked via the Nuclear Commitment
Tracking System (NCTS).
The licensee is currently drafting a
Nuclear Division Management Policy on this subject.
The current backlog is still substantial:
approximately 242 items on Unit
and 1131 items on Unit 2 as of the first week of April.
The licensee indicated that 50% of these items were in either final review or concurrence stages.
The inspector will review licen-see's progress in a future inspection.
This item will remain open.
2.2 Unit 2 (Closed) Violation (50-410/88-21-01):
Violation of Technical Specification 3.3.3, unit operation in modes 1,
2 and 3 with Division I of the Automatic Depressurization System (ADS) in-operable.
The licensee did not address restoration of Division I ADS to an operable status in their reply to the Notice of Violation; however, procedure N2-ISP-ISC-R104, revision 1,
com-pleted January 30, 1989, demonstrated operability of ADS.
This item is closed.
- (Closed) Violation. (50-410/88-21-02):
Failure to take timely and appropriate corrective action to correct an identified con-dition adverse to. quality; the licensee had two opportUnities to identify the ADS logic circuit wiring deficiency, but, did not adequately pursue technical resolution of the problem.
Station General Order 89-03, dated Narch 17, 1989, requires:
surveil-lance tests be performed to the maximum extent possible, tests be rescheduled or changed when specified plant conditions cannot be met; and steps be performed as written or the Station Shift Supervisor (SSS) notified.
In addition, when notes are used they must be reviewed and signed off by the department super-visor, and incomplete portions of tests must be reported to the duty SSS.
All plant personnel have been trained on Station General Order 89-03.
A noticeable improvement in procedure adherence has subsequently been noted.
This item is closed.
(Closed) Violation (50-410/86-56-04):
Failure to maintain the minimum number of operable reactor building radiation monitors.
Discussions with the licensee on January 8,
1987 following their investigation (and subsequent to the issuance of Inspection Report 50-410/86-56)
into this incident indicated that the Tech-nical Specification requirement regarding the minimum number of operable reactor building radiation monitors was not exceeded.
Therefore, a notice of violation for this finding was never issued, although it remained documented and tracked in the inspection report.
This item is close (Closed)
Inspector Followup Item (50-410/85-20-05):
Licensee to determine the capability of the process and effluent monitoring system to collect representative samples.
By internal corres-pondence dated February 22, 1989 ( File Code NMP-45731),
the licensee is tracking this issue and estimates that this item will be completed in September 1989 due to the need to conduct sampling at the top of the vent stack.
This item is closed for administrative purposes since the licensee is tracking completion.
(Closed)
Licensee Actions on IE BULLETIN 85-03: Motor-Operated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings.
The inspector reviewed Inspection Report 50-220/88-24 and 50-410/88-26 regarding the licensee's actions relative to IE Bulletin 85-03 as well as all pertinent corres-pondence.
The inspector identified no concerns during this review and considers this bulletin closed.
(Closed) Violation (50-410/88-07-0))
( 1) Technical Specification
.
4.6. 1.2.d regarding Type B local leak r ate testing was violated in that containment penetration Z-74 was not tested within 24 months and (2) TS 4. 11.2. 1.2 was violated in that a sample of the primary containment was not taken prior to commencing a purge of the containment.
The licensee's response to the notice of violation, dated June 30, 1988, stated that Niagara Mohawk instituted a daily data input verification process which assures that entries made to the master database are reviewed for cor-rectness and,completeness by Planning Department personnel.
Furthermore, the licensee performed a
100'o review of the com-puterized Master Surveillance, Scheduling database versus Sur-veillance Test Procedures to assure that all Technical Specifi-cation surveillances are properly scheduled and assigned correct periods.
Finally, to assure that TS 4.6. 1.2.d was met, a Lessons Learned Transmittal was issued by the Operations Department on April 13, 1988 to address the changes made to the containment purge procedure.
The inspector reviewed a file memo to the Station General Super-intendent detailing the results of the surveillance review summary which the licensee committed to perform.
No violations of the Technical Specifications were identified as a result of this review.
General concerns identified by the review were properly tracked by the licensee's commitment tracking system.
The licensee issued Temporary Change Notice (TCN)"38, dated October 6, 1988 to procedure N2-OP-61A regarding the containment sampling provisions of TS 4. 11.2. 1.2.
The inspector reviewed the TCN and procedure N2-OP-61A.
No problems were noted.
This violation is close (Closed)
Inspector Followup Item (50-410/87-08-03):
Yendor pro-vided incorrect Category 1 certification of electrical components.
On June 1,
1987, the licensee submitted a written
CFR Part
report to the NRC concerning the identification of incorrect Category 1 certification of certain spare electrical components supplied by the Brown Boveri Corporation for safety-related applications.
The licensee's investigation into this incident found that of the 23 specific components supplied to the licensee by Brown Boveri with incorrect certification, only one component was installed for safety-related applications.
That breaker was replaced per Engineering and Design Change Request (E&DCR) C95036.
Of the 23-components noted, 15 components were found to be stored in the licensee's warehouse (including the one component'emoved by E&DCR C95036),
seven components were in use in non-safety related applications and one componen was returned to the vendor.
The licensee subsequently submitted a letter to the NRC, dated July 9, 1987, which stated that Brown Boveri had identified addi-'ional items that were incorrectly certified for use in safety-related applications.
The licensee determined that of those items, eight specific part numbers, comprising a total of 59 items, were installed or authorized for installation in safety-related applications.
Brown Boveri was later able to provide qualification. data for seven of the eight part numbers.
The remaining component part number, comprising a total of 20 com-ponents, was determined not to be in use by the licensee due to a previous design change.
The inspector reviewed Work Request No.
116905, which replaced the unqualified component designated by E&DCR C95036, as well as Nonconformance Reports 2-87-0037,
-0043, and -0060 documenting the licensee's tracking and resolution of this problem.
No problems were noted as a result of this inspection.
The licen-see appears to have thoroughly researched this problem and followed through with comprehensive corrective actions.
This item is closed.
(Closed)
Unresolved Item (50-410/87-20-04):
A transverse incore probe (TIP) was retracted beyond it's shield and resulted in an unplanned personnel exposure.
The inspector reviewed corrective actions taken to prevent recurrence and found them to be satis-factory.
I&C technicians were given training on the radiological hazards associated with an exposed TIP.
I&C procedures were
~
revised to enhance precautions during TIP probe movements..
A modification is planned for the next refuel outage to provide a
brake assembly to prevent unwanted TIP probe movement.
, This item is close.
Plant Ins ection Tours (71707, 71710)
During this reporting period, the inspectors made tours of the Unit 1 and 2 control rooms and accessible plant areas to monitor station activities and to make an independent assessment of equipment status, radiological conditions, safety and adherence to regulatory requirements.
The following were observed:
3.1 Unit
The inspectors conducted routine inspections of the turbine and reactor buildings.
No concerns were identified.
3.2 Unit 2 The inspector observed the startup of Unit 2 from the unplanned shut-down on April 13, 1989.
Specifically, he reviewed Operating Procedure N2-0P-101A, Revision 6, "Plant Startup" and observed the licensee performing turbine chest warming and turbine rollup to 1800 RPM.
He also walked down the control panels to verify proper system lineups and the operability of required equipment.
No problems were noted.
The operators were knowledgeable of the procedure and performed the noted operations without incident.
During performance of the above startup activities, the licensee per-formed routine monthly surveillance, test N2-0SP-EGS-M001, Diesel Generator and Diesel Air Start Valve Operability Test, Division I/II.
The inspector observed the starting of the diesel generator for Division I, reviewed key Technical Specification prescribed parameters, and reviewed the test data during, the 60 minute operation of the diesel.
No problems were noted.
The operators performed the sur-veillance test professionally and in accordance with the procedure.
Effective communications were maintained between the control room and the operator at the diesel generator monitoring panel at all times.
During a tour of the control room at Unit 2 on April 19, 1989, with the plant at 50% power and increasing, the inspector noted that annunciators 602218 and 602224 (NSSS Division I 8 II Isolation) were actuated.
Review of the licensee's alarm response procedures for these alarms revealed that no alarm response procedure existed for these annunciators.
However, discussions with the Station Shift Supervisor (SSS),
who was clearly knowledgeable of the alarms, indi-cated that the annunciators were installed during the last outage and
an alarm response procedure had yet to be approved for the annunci-ator.
The annunciators were lit.due to the existence of a Group 8 isolation, shutdown cooling system secured, a normal condition.
However, another isolation signal would cause the annunciator to reflash, preventing a masking of a valid isolation signal from the operator.
During tours of the plant, the inspectors noticed good plant cleanli-ness.
4.
Surveillance Review (61726)
4.1 Unit
While touring the plant throughout the inspection period, the inspectors observed portions of various surveillance tests in progress at the time.
No concerns were identified by the inspectors regarding the surveillance tests observed.
4.2 Unit 2 The inspectors observed portions of the surveillance testing listed below to verify that the test instrumentation was properly calibrated, approved procedures were used, the work was performed by qualified personnel, limiting conditions for operations were met, and the system was correctly restored followi'ng the testing.
LPRM gain adjustments Division II Emergency Diesel Generator operability test No concerns were identified by the inspector during these surveillances.
5.
Maintenance Review (62703)
The inspector observed portions of various safety-related maintenance activities to determine that redundant components were operable, that these activities did not violate the limiting conditions for operation, that required administrative approvals and tagouts were obtained prior to initiating the work, that approved procedures were used or the activity was within the "skills of the trade", that appropriate radiological controls were implemented, that ignition/fire prevention controls were properly implemented, and that equipment was properly tested prior to returning it to service.
The inspector reviewed the'icensee's program for Preventive Maintenance (PM) of instorage equipment by selectively verifying licensee records and instorage conditions.
The inspector had discussions with various licensee representatives in Maintenance, Material Management, and Material Engineer-ing departments, and reviewed several related procedures.
The licensee's
administrative procedure AP 8. 1, Preventive Maintenance, requires that the allowable PM schedule tolerance does not exceed
+25 of the scheduled interval including 3.25 times the interval for three consecutive maintenance intervals.
The inspector observed that this requirement was not consistently reflected in the procedures reviewed.
The licensee stated that the above limit has no basis for application to PM scheduling, and AP 8. 1 would be revised to reflect a +25<.'olerance without the 3.25 limit.
The inspector determined that PM on instorage equipment has long been identified as a concern by the licensee.
The inspector noted that Correc-tive Action Request (CAR) 85.3077 issued by the Station Quality Assurance Department for an inadequate program for PM in storage is not yet resolved.
Although the licensee implemented a progr'am for PM of instorage equipment, they are slow in developing, implementing and evaluating the program.
The resolution of CAR 85.3077 appears to be inordinately delayed.
The inspec-tor will review the licensee's resolution of this concern in a future inspection.
5.1 Unit
The inspectors observed maintenance performed on the support legs of the condensate demineralizers as well as preparations for correcting weld defects found on the feedwater pumps.
No discrepancies were noted.
5.2 Unit 2 On January 4,
1989, an exhaust rocker arm broke on a Cooper-Bessemer Diesel Engine at Palo Verde Nuclear Power Plant.
All rocker arms were inspected on their six emergency diesel generators (EDGs)
and a
second rocker arm was found cracked.
The vendor notified Niagara Mohawk to perform an inspection of all rocker arms on the Division I and'I EDGs which are also manufactured by Cooper-Bessemer.
The licensee completed their inspection on February 4 and identified no failures or evidence of cracking.
No concerns were identified by the inspector.
6.
Review of Licensee Event Re orts LERs (92701)
The LERs submitted to the NRC were reviewed to determine whether the details were clearly reported, the cause(s)
properly identified and the corrective actions appropriate.
The inspectors also determined whether the assessment of potential safety consequences had been properly evaluated, whether generic implications were indicated, whether the event warranted on site follow-up, whether the reporting requirements of 10 CFR 50.72 were appli-cable, and whether the requirements of 10 CFR 50.73 had been properly met.
(Note: the dates indicated are the event dates)
6.1 Unit
a.
The following LER was reviewed and found to be satisfactory:
LER 89-01, 3/3/89.
Failure to perform surveillance testing according to Technical Specifications due to procedural defici-ency.
This LER is discussed in Section 1 of the report,.
6.2 Unit 2 a.
The following LERs were reviewed and found to be satisfactory:
LER 88-34, 7/23/88, Engineered Safety Feature initiations due to spurious trip signals caused by equipment malfunctions.
LER 88-33, 4/29/88, Technical Specification violation occurs as a result of missed leak rate surveillance due to personne'1 error.
LER 88-32, 7/15/88, Design deficiency and subsequent inadequate review in the reactor bui lding ventilation system could have prevented fulfillment of the system's safety function.
LER 88-47, 9/15/88, While troubleshooting fuses to the radiation monitor, a personnel error caused an ESF actuation.
LER 88-46, 9/15/88, An Engineered Safety Feature not single failure proof due to a design deficiency.
LER 88-45, Design rated reactor core flow exceeded due to per-sonnel error-results in plant operations in an unanalyzed condition.
LER 88-42, 8/16/88, Emergency Safety Feature actuation due to a
design deficiency.
LER 88"37, 8/3/88, Reactor Core Isolation Cooling system procedural deficiency results in a system isolation.
LER 88-35, 7/21/88, Special filler-train actuation due to spurious radiation monitor trips caused by electrical noise.
LER 88-60, 10/10/88, Missed surveillance of Radiation Monitor 2SWP RE146B due to a programmatic deficiency.
LER 88-59, 10/25/88, Engineered Safety Feature actuation caused by power source shorting to ground flex conduit contacts on heat sink plates of power source.
7.
Review of Licensee Re orts (92701)
7. 1 Review of S ecial Re orts The following Special Reports were reviewed by the inspectors:
a.
UNIT I Special Report dated December 1,
1988; NMP 42127 Special Report dated December 15, 1988; NMP 42656 Special Report dated January 12, 1989; NMP 43474 Special Report dated February 17, 1989; HMP 46208 Special Report dated April 11, 1989; NMP 49013 Special'Report dated April 12, 1989; NMP 49015 t
It was determined that the reports were issued within 30 days and that proper compensatory measures were initiated as required by the plant's Technical Specifications.
Each of the reports contained several events which required issuance of an Occurrence Report and subsequent inclusion in the Special Report.
Event breakdown is as follows:
8 events related to non-functional fire barriers reported per TS 3.6.10.1.d.
5 events related to non-functional Pre-Action Sprinkler Systems reported per TS 3.6.7.g.
2 events related to inoperable detection equipment reported per TS 3.6.6.a.2.
1 event related to an inoperable halon fire suppression system reported per TS 3.6. 10.2.c.
b.
Unit 2 Special Special Special Special Special Report dated January 17, 1989 Report dated March 17, 1989 Report dated January 16, 1989 Report dated January 16, 1989 Report dated November 3, 1988 The inspector determined that the reports were issued on time, and proper compensatory measures were taken.
Event breakdown is as follows:
Two events related to the inoperability of seismic monitor-ing instrumentation were reported per TS 3.3.7.2.
Two events related to Emergency Diesel Generator failures during surveillance testing were reported per TS 4.8. 1. 1.3.
One event related to the inoperability of the Gaseous Effluent Monitoring System was reported per TS Table 3.3.7.10-1.3 and 1.4.
No concerns were identified by the inspecto.2 Review of Part
Re ort On February 24, 1989, the licensee supplied written notification to the NRC Region I office of a
CFR Part 21 reportable condition.
Specifically, a deficiency was identified in the First 10 Year Interval Inservice Inspection ( ISI) Program at Nine Mile Unit 1, which is required by
CFR 50.55 a(g).
The First 10 Year ISI Program was prepared by Nuclear Energy Services (NES), Incorporated, who was also the primary contractor responsible for performing the nondestructive examinations (NDE) required by the program.
The deficiencies identified by Niagara Mohawk in the First
,
10 Year ISI Program included omissions in the plan, documentation deficiencies, and deficiencies in the NDE procedures.
The deficiencies identified in this Part 21 Report have been previously reported by the licensee and discussed in previous NRC inspection reports.
The licensee corrective actions are more completely identi" fied in their letter NMP1L 0246, dated April 13, 1988, and additional actions to prevent recurrence of such deficiencies are addressed in the Restart Action Plan.
The inspector found this Part 21 Report to be satisfactory and had no further questions.
8.
Tens orar Instruction Followu
-~Unit I (25593, 25100, 25595, 25596)
Diesel Generator Fuel Oil Review (TI 2515/93 and 2515/100)
For proper operation of the standby diesel generators, it is necessary to ensure proper quality of the fuel oil.
Appendix B to
CFR 50, as supplemented by Regulatory Guide (RG)
1. 137, serves as an acceptable basis for licensees to maintain a program to ensure the quality of diesel generator (DG) fuel oil.
In response to recent industry problems, the NRC issued an Infor-mation Notice on January 16, 1987 to alert licensee and NRC personnel
"of potentially significant problems pertaining to long-term storage of fuel oil.
In addition, temporary inspection guidance was prepared to assess current licensee practices.
The inspectors reviewed the following surveillance procedures and the Material Control System and verified that the DG fuel oil is controlled and procured as a safety related consumable item for Nine Mile Point Unit 1 (NMP1):
NMP 1 Mechanical Maintenance Procedure No.
N1-NMP-GEN-850,
"Maintenance of Diesel Engine and Auxiliaries" 2/24/88.
NMP 1/2 Sampling Procedure No. S-SP-4,
"Sampling of New Generator Fuel Oil Prior to Tank Loading Diesel Fuel Oil Storage Tanks" 5/6/8 NMP 1 Sampling Procedure No. NI-SP-5,
"Sampling of Diesel Fuel Oil Storage Tanks" 3/6/86.
NMP 1 Chemistry Surveillance Procedure No. Nl-CSP-8M, "Diesel Fuel Oil Analysis" 3/14/88.
NMP 1 Operating Procedures No. Nl-OP-45,
"Emergency Diesel Generators System No. 82" 10/6/88.
-The inspector also reviewed the NMP1 response to I&E Information Notice 87-04.
In their response, dated August 18, 1987, the licensee identified deficiencies in the areas of preventive maintenance and chemistry.
These deficiencies were evaluated and subsequently corrected by procedural changes requiring monthly fuel oil sampling for biolog-ical contamination, and transfer pump suction strainer inspection and cleaning once per cycle.
The inspector noted that no specific action or written response was required from the licensee in response to I&E Notice 87-04.
Additionally, the licensee was not required to imple-ment RG 1. 137, which describes many of the methods identified in I&E Notice 87-04, to ensure adequate quality fuel oil.
After further review and discussions with licensee representatives, the inspector found that the licensee's response to I&E Notice 87-04 had not fully addressed industry practices that have been found to be contributing or mitigating factors to fuel oil degradation or fuel system component failures.
The licen'see initi'ated a problem report (PR-1229) to further evaluate, as a minimum, the following issues raised during the inspection:
1.
The inspector found that the licensee had not evaluated the requirement in Regulatory Guide (RG)
1. 137 to clean and inspect fuel oil storage tanks at a minimum of ten year intervals.
The inspector determined that the NMPl fuel oil storage tanks were recently replaced due to the age of the installed tanks, and because their "single-tank" construction made them more suscepti-ble to failure.
2.
The inspector found that NMP1 Technical Specifications do not contain requirements for DG fuel oil surveillance or operations.
The inspector also found that the licensee does not maintain procedures identifying required operator actions for fuel oil test results that exceed the limits specified in procedure Nl-CSP-8M.
The inspector discussed with the licensee the RG 1. 137 position that the diesel should be considered inoperable if test results for viscosity, water or sediment exceed established limits.
Additionally, fuel oil not meeting applicable specifi-cations should be replaced in a short period of time (about one week).
3.
The inspector questioned the licensee regarding their ability to conduct fuel oil filtration to remove accumulated particles with a permanent fuel oil recirculation system.
The licensee indicated that NMP 1 currently has no requirements for a fuel oil recircu-lation system.
4.
The inspector found that the licensee had not evaluated the practice of sampling the fuel oil day tanks for water or other contaminants.
=5.
The inspector found that the licensee samples fuel oil storage tanks at 6 inches from the tank bottom, and had not evaluated the recommended practice of sampling at the lowest point in the fuel oil storage tank,,s.
6.
The inspector found that the licensee had not evaluated the practice of adding a fuel additive as a chemical stabilizer to prevent fuel oil oxidation and bacterial growth.
7.
The inspector found that the licensee had not evaluated recom-mendations to sample the fuel oil day tanks for water after diesel operations for periods greater than one hour.
8.
The inspector found that the licensee had not evaluated the practice of maintaining a procedure for removing water if found during sampling of the fuel oil storage tanks.
In summary, the items discussed in TI 2515/93, to verify that fuel oil is included in the NMP1 guality Assurance Program, have been addressed and this TI is closed.
However, the iterrs discussed in TI 2515/100, to verify that the licensee has a program to purchase and store fuel oil that meets current industry good practices, are considered open.
The inspector's review of licensee records and discussions with licensee representatives found that NMPl had not adequately reviewed industry experience regarding the factors contributing to fuel oil degradation and fuel system component failures.
The concerns from this review resulted in the licensee issuing PR-1229.
The resolutions to PR-1229 will be reviewed in a subsequent inspection.
TI 2515/100 remains open pending this review.
b.
Recirculation Pump Trip Review (TI 2515/95)
One of the requirements of 10 CFR 50.62,
"Requirements for reduction of risk from anticipated transients without scram (ATWS) events for light-water-cooled nuclear power plants,"
was a requirement for each boiling water reactor (BWR) to include equipment to trip the reactor recirculation pumps automatically under conditions indicative of an ATWS.
The NMP1 design includes recirculation pump trip on either low reactor vessel water level or high reactor vessel pressure.
The
inspector reviewed the checklists for Instrument Surveillance Proced-ure NI-IPM-g-036-009, "Anticipated Transient Without Scram (ATWS)/
Alternate Rod Injection (ARI) Instrument Channel Test", dated 8/24/88, to verify that these modifications" had been completed.
This procedure contains the surveillances for the recirculation pump trips on high reactor vessel pressure and low vessel level.
The inspector reviewed completed surveillance tests on the subject instrumentation conducted in December, 1988.
No problems were identified.
TI 2515/95 is closed.
c.
Drywell Vacuum Modification Review (TI 2515/96)
Generi'c Letter (GL) 83-03 identified concerns relating to a potential failure mode of the vacuum breakers on Mark I containments under LOCA loads.
The inspector reviewed licensee submittals dated July 22, 1983, and March 7, 1986, containing vacuum breaker load analyses, and the subsequent NRC review and safety evaluation dated November 24, 1986.
In the safety evaluation, the NRC concluded that vacuum breakers at NMP1 will provide adequate margins of safety under the revised loadings in the Hark I containment for all conditions, and therefore need not be modified.
The inspector had no further questions.
TI 2515/96 is considered closed.
9.
Assurance of ualit (30702, 30703, 83723)
Several events that occurred during Unit 2 operation this inspection period indicate a negative performance trend.
These events include the following:
Two reactor scrams, one of which was caused by operator error.
Violation of TS minimum number of operable main steam line radiation monitors due to errors made during the shift data-taking and review process.
A non-conservative interpretation of the operability requirements of the High Pressure Core Spray system without a supporting safety evalu-ation required by
CFR 50.59.
A locked high radiation area door was found unlocked which is a poten-tial violation of TS.
This is of particular concern because this has occurred several times before.
Incorrect independent verification of valve positions by technicians that occurred during the mid-cycle outag The inspectors do not draw any additional conclusions from these events at this time, but will continue to 'closely monitor licensee overall performance.
Review of Special Reports required by TS found them to be prompt and tech-nically correct.
Initial NMP1 response to the recent diesel generator fuel oil problems was considered shallow; however, licensee response to the inspector's followup questions were appropriate.
~Heetin s (40500)
Several Station Operations Review Committee (SORC) meetings were-observed during the inspection period.
Meetings attended were well-structured and systematic in the review of the topics discussed.
The inspectors found the SORC discussions to be probing and with clear focus on safety and good practice.
The residents observed an Operations-Training meeting held on 5/2/89.
The meeting was noted to be well attended with the Operations and Training
'groups well represented.
Other personnel were in attendance including a
member of the QA organization who was auditing the meeting in connection with the Restart Action Plan.
The inspectors noted a good, professional atmosphere throughout the meet-ing.
Training personnel were responsive to concerns and criticisms pre-sented to them.
Similarly, the Operations personnel were supportive of Training Department initiatives requiring the assistance of operators.
One such program was the new requalification program for licensed opera-tors which require operator support for the validation of Job Performance Measures, simulator scenarios and static simulator test questions.
Other topics and initiatives were discussed as well.
Additionally, several issues discussed were proactive in nature, such as the scheduling of simu-lator time over the next few months in order to support operator training needs, NRC examinations, formulation and validation of requalification examination questions,
'as well as, upgrades and modifications to the simu-lator.
Overall the meeting was observed to be productive and woi thwhile for the licensee.
Good cooperation between the groups was noted and the inspectors did not sense any tension between the groups represented.
No concerns were identified by the inspector ~Ei i
t>>i>>)
At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings
'of this inspection.
Based on the NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain Safeguards or
CFR 2.790 information.