IR 05000220/1987013
| ML17055D273 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 10/05/1987 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17055D271 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.K.3.02, TASK-TM 50-220-87-13, 50-410-87-29, IEB-79-27, IEB-80-25, NUDOCS 8710160279 | |
| Download: ML17055D273 (26) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION-REGION I Report No.
Docket No.
License No.
87-13/87-29 50-220/50-410 DPR-63/NPF-69 Category B
Licensee:
Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Faci l ity:
Location:
Dates:
Inspectors:
Nine Mile Point, Units 1 and
Scriba, New York July 20, 1987 to August 30, 1987 W.A. Cook, Senior Resident Inspector C.S. Marschall, Resident Inspector W.L. Schmidt, Resident Inspector N.S.
Perry, Resident Inspector, Ginna Approved by:
.R. Johnson, Chief, Reactor Projects Section 2C, DRP
>O(d ( Sg Date INSPECTION SUMMARY Areas
~Ins ected:
Routine inspection by resident and region based inspectors of station activities (including Unit 1 power operations and Unit 2 power ascension testing),
plant tours, surveillance testing, safety system walkdowns, physical security review, radiological protection review, LER review, TMI Action Plan review, IE Bulletin review, and a Non-Essential EDG
.
trips review.
This inspection involved 381 hours0.00441 days <br />0.106 hours <br />6.299603e-4 weeks <br />1.449705e-4 months <br /> by the inspectors which included 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> of backshift and 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of weekend inspection coverage'ackshift inspections were conducted on 7/20-24, 7/27-31, 8/3-4, 8/17-21, and 8/25-28.
Weekend inspections were conducted, on 7/19, 7/26; 8/1, and 8/22.
Results:
Two violations.and one unresolved item were identified during this inspection period.
One VIOLATION concerning the failure to meet a Technical Speci'fication LCO for shutdown cooling is discussed in section 1.2.e.
A VIOLATION concerning the fai'lure to comply with the station Fire Protection Program is discussed in section 2.2.a and is indicative of poor housekeeping'n UNRESOLVED item concerning access controls to the Unit 1 storeroom is
.discussed in section 2'.b.
Licensee (Unit 1) response to IE Bulletin 80-25 requires revision and is discussed in section 9.'1.b.
8710160279 871008 PDR ADDCK OS000220
Several Unit 2 Reactor Building Ventilation system isolations and automatic Standby Gas Treatment system actuations occurred during this period due to personnel error s in sequencing fans and damper s or in improper use of jumpers and are discussed in section 1.2.c.
A concern regarding poor'housekeeping and storage of anti-contamination clothing is discussed in section 6. e
DETAILS 1.
Review of Plant Events 1.1 UNIT 1 The plant operated near full power throughout the period.
On August 26, 1987, the NRC observed the annual emergency exercise.
Combined Inspection Report 50-220/87-19 and 50-410/87-31 contains details of the drill and NRC observations.
1.2 UNIT 2 a
b.
C.
On July 22, 1987, the licensee requested and was granted an emergency Technical Specification (TS) change to specification 3.7. 1. l.b.
The change allowed the plant to operate with a servi'ce water supply header discharge temperature limit of 77'ice 76'ahrenheit (F).
On July 25, the reactor was. shutdown to comply with TS action state-ment 3.7. 1. l.e, when service water supply header temperature exceeded
F for more than eight hours'ervice water temperature dropped below 77~F on July 26 and the reactor was returned to criticality on July 27.
The inspectors monitored licensee compliance with this Technical Specification and the resultant unit shutdown.
No discre-pancies were noted.
On August 3, the licensee submitted a
TS amendment to permit opera-tion of the unit with a service water supply header temperature limit of 81~
F.
This amendment is currently under review by the NRC staff.
During this inspection period, Reactor Building Ventilation (RBV)
and Standby'Gas Treatment (SBGT) system automatic isolations and initiations, respectively, continued to be a problem area for the licensee.
On July 25, two isolations of RBV occurred.
The first was due to a jumper grounding during surveillance testing on the RBV above-the-refuel floor radiation monitor.
The ground short caused a control power fuse to blow and its associated damper to reposition.
The repositioning of the damper caused a
RBV low flow condition which resulted in the RBV isolation.
While restoring the normal ventilation lineup, another RBV isolation occurred due to the fan starting sequence used.
An exhaust fan was started, but tripped on high reactor building differential pressure because a supply fan was not started soon enough.
The exhaust fan trip caused a low flow condition and subsequent RBV isolation signa On July 29, two more RBV isolations occurred.
While performing concurrent monthly surveillances on train A of SBGT and the RBV above the refuel floor radiation monitor, a test signal fed to the radiation monitor resulted in a RBV isolation signal.
The licensee failed.to jumper out a
RBV damper which actuated to cause a ventilation low flow condition when the test signal was introduced.
During restoration of the normal RBV lineup, an exhaust fan tripped while two supply fans were operating.
This caused a
RBV low flow condition and resulted in the second RBV isolation.
On August 25, while restoring RBV to a normal lineup after the completion of a SBGT surveillance test, a
RBV isolation occurred.
The licensee attributes this event to a procedural deficiency in the fan starting sequence.
The inspector will review licensee action to correct these deficiencies in a subsequent report.
On July 30, with the reactor operating in MODE 1, it was discovered that a surveillance had not been performed on the Average Power Range Monitor (APRM) nuclear instruments flow bias upscale trip function.
This surveillance is required to be performed prior to entering MODE 1 by TS 3.3. 1.
The test procedure had been changed previously to delete this section because it was not required in MODES 2 through 5.
When the surveillance procedure was last performed on July 28, in preparation for entering MODE 1, the APRM flow biased section was still deleted.
The licensee did not identify this procedure oversight during their surveillance test review prior to entering MODE 1.
L This is a violation of TS 3.3.1, however, a Notice of Violation is not being. issued as provided by 10.CFR 2, Appendix C,Section V.
The, licensee identified this violation and promptly reported it to the NRC.
The violation is of minor safety significance, in that the APRM "high level flux" trip was set more conservative than the
"flow bias upscale" trip.
The APRM "high level flux" trip setpoint was set low for initial power operation during power. ascension testing.
The licensee corrective action was timely and positive, in that a
shutdown was commenced to take the plant out of MODE 1 when the condition was identified.
There have been no previous events of this nature at Unit 2.
NO VIOLATION ISSUED (50-410/87-29-03)
On August 13, at 3:23 a.m., while in the shutdown cooling mode of Residual Heat Removal (RHR),
shutdown cooling isolation valve RHS"MOV112 went shut unexpectedly.
This caused the RHR pump to trip and the total loss of coolant circulation.
Testing of the RPS vital bus electrical protection assemblies (EPA) was in progress at the time.
When the Division I EPA was tripped open, it removed power from the Division I Nuclear Steam Supply Shutoff System (NSSSS)
isolation circuit as expected.
This power interruption also
resulted in the power loss to the Division II NSSSS logic, causing RHS*MOV112 to go shut and the res'ultant tripping of the running RHR pump.
Although not known at the time this event occurred, loss of power to the Division I RPS and NSSSS logics results in both outboard and inboard (Division II) RHR shutdown cooling valves isolation.
This is a unique design feature for protecting the shutdown cooling system from overpressurization.
The Station Shift Supervisor (SSS),
knowing that TS 3.4.9.2 required that coolant circulation be reestablished within one hour, attempted to get the EPA shut to restore power to the NSSSS logic.
Due to a
fault in the EPA, power could not be restored and the isolation logic could not be reset.
The SSS directed that troubleshooting commence to correct the EPA fault, however, the electricians discovered that the EPA could not be readily repaired.
The SSS then directed that the motor control breaker for RHS"MOV112 be opened and the valve opened manually.
Concurrently, reactor coolant temperature and pressure was monitored as required by TS.
Coolant circulation was not restored until 5:25 a.m.
The Technical Specification 3.4.9 '
one hour Limiting Condition for Operation for shutdown cooling was exceeded at 4:23 a.m.
This is a violation.
VIOLATION (50-410/87-29-01).
The safety significance of this LCO.
violation is low.
The amount of decay heat being generated by the reactor resulted in a coolant temperature rise from 130 to 145'ahrenheit during the two hour period there was no circulation.
In addition, operators were monitoring the temperature rise while troubleshooting the problem.
On August 22, the licensee determined that control rod ¹10-47 had scrammed from position 48 to 00.
This single rod scram had gone undetected (no.rod drift alarm was received) until operators attempted to raise reactor power by pulling control rods.
The rod wort'h minimizer indicated a rod select error and upon'nvestigating the operators found that rod ¹10-47 was at position 00 and that the power supply fuse for the B scram solenoid valve was blown.
It was later determined that a rod position bottom light was lit but was not noticed at the time.
Earlier that evening, the licensee was conducting Intermediate Range Neutron Monitor ( IRM) surveillance testing which results in Reactor Protection System half scrams, (deenergizing either the A or B scram solenoid valve).
The licensee speculates that after the Division I IRM (A solenoid) surveillance test half scrams were completed'and the half scram sign'al was.reset, the A scram solenoid for rod ¹10-47 failed to properly reposition.
When the Division II IRM surveillance test half scrams were inserted, both A and B solenoids for rod ¹10-47 were.positioned/deenergized to vent air from the control rod scram valves and the rod scrammed.
The inspector reviewed and discussed this event with licensee representatives involved.
Licensee investigation of the cause of the event and reverification of proper systems, instrumentation and
annunciator response was determined to be satisfactory.
With the exception of the blown fuse, all systems functioned as designed and the A solenoid repositioning problem could not be duplicated.
Licensee and General Electric engineers stated that a rod drift alarm may not be received if a fast rod scram occurs and the computer is scanning a different group of rods at that time.
A process computer printout did identify that rod //10-47 had scrammed, but this computer point does not have, an associated audible alarm.
2.
Plant ~lns ection Tours.
During this reporting period, the inspectors made tours of the Unit
a'nd 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:
2. 1 Unit
a
~
Section 2.2, below supplies details of an inspector identified Fire Protection Program. violation at Unit 2.
As discussed in that section, the violation is one example of a Unit 2 programmatic weakness in the area of housekeeping.
This weakness is also evident at Unit 1.
Plant tours of the Unit 1 reactor building during this inspection period revealed numerous instances of inadequate housekeeping on the 198', 218'nd 237'levations.
These examples, together with the results of conversations with plant personnel, indicate a lack of positive motivation of plant. personnel to perform every aspect of their jobs to the highest standards, and in particular, housekeeping.
Plant personnel interviewed indicated that many negative motivation factors presently exist.
These factors include: the austerity program;.dilution of authority; lack of management receptiveness to new ideas; the "distinctive clothing" (uniforms) initiative; and recent enforcement history, among others.
Unit 1 management indicated that housekeeping has shown steady improvement in the recent past and efforts will continue towards further improvement.
It was also noted that morale is currently low.
This was considered by station management to be a cyclic phenomena caused by some of the events given above.
Station management believes that morale will recover in time and that., overall, plant personnel are highly motivated to standards of excellence.
Inspectors will continue to monitor housekeeping and will survey employee motivation in future inspection period b.
While conducting a tour of the station grounds, the inspector noticed that access to the Unit 1 storeroom from outside the building was not controlled.
Further investigation revealed that available means for securing two doors which provide outside access was ineffective and could be easily defeated.
This condition could permit undetected storeroom access from outside during periods when
'o one was present in the storeroom.
The impact of the lack of access control has not been determined and will be reviewed in a future inspection report.
This item is unresolved.
UNRESOLVED ITEM (50-220/87-13-01).
2.2 Unit 2 a
~
On July 28 and August 26, 1987, the inspector observed oily rags at the base of the Division I and II emergency diesel generators (EDGs)
and puddles of fuel oil on the diesel skid.
Rags were placed at the base of the EDGs to collect lubricating oil that was leaking from the inspection covers.
Resident and region based inspectors have addressed these observations with licensee management on earlier occasions and have expressed a concern that this practice was a
potential fire hazard and indicative of poor housekeeping.
Station Fire Department Procedure N2-FDP-7 specifies that any leakage of flammable or combustible liquids shall be contained and cleaned up promptly and that the cleanup material shall be stored in covered metal containers'he above findings are violations of procedure N2-FDP-7.
VIOLATION (50-410/87-29-02)
.
3.
Surveillance Review I
The inspectors observed portions of the surveillance test procedures 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 following the testing.
3.1 Unit 1 The following surveillances were observed:
Nl-ST-V4, Revision 8, effective August 1987, Feedwater and Main Steam Line Isolation Valve Exercise Test.
-.- N1-ST-W1, Revision 7, effective October 1986, Control Rod Exercising.
Nl-ST-W6, Revision 7, effective May 1987, APRM Rod Block and and Scram Instrumentation Calibration.
No unacceptable conditions were note.2 Unit 2 The following surveillance was observed N2-ICP-MSS-QOOl, Revision 0, effective May 1987, Stroke Time Calibration for Main Steam Isolation Valves.
This procedure was being performed due to potential problems with slow closure.
During its performance, the inspector observed rubbing/scraping of the spring guides.
The licensee considered this normal and the valve closed in 'less than 60 seconds, as required.
While observing the valve stroking, the inspector noted that the valves had not been covered during recent lagging work in the steam tunnel.
There was a visible buildup of dust and insulation particles on the valve bodies.
The licensee concluded that the slow valve stroking was attributable.to dry packing and not a buildup of dirt and debris on the valve stem and spring guides.
Operations management stated that attention would be given to cleaning up the main steam isolation valves in the steam tunnel.
No violations were identified.
~~~ill V if'*
On a sample basis, the inspectors directly examined selected safety systems to verify that the systems were properly aligned in the standby mode.
The following systems were examined:
4.1 Unit
The inspector walked down each of the four Containment Spray subsystems, each of the four Core Spray subsystems and portions of the Drywell and Torus Vacuum Relief system.
Discrepancies were noted with'egard to housekeeping in all areas inspected, as discussed above.
No discrepancies were noted which directly impacted operability of the systems inspected.
4.2 Unit 2 The following systems were reviewed:
Standby Liquid Control System Emergency Diesel Generators Other than previously noted in section 2.2.a, no unacceptable conditions were identifie ~iRh sicai ~Secnrit Review The inspector made observations to verify that selected aspects of the station physical security program were in accordance with regula'tory requirements, physical 'security plan and approved procedures.
Unit 1 and Unit 2 The inspector observed access control and questioned security personnel to insure the measures specified in the security plan were effective-and being utilized.
In addition, portions of the protected area perimeter were visually inspected.
No unacceptabl'e conditions were noted.
~Ri
1
1
The inspector reviewed selected aspects of the licensee's rad'iological protection program to verify that the stations policies and procedures were in compliance with regulatory requirements.
Unit 1 and Unit 2 In some areas, poor housekeeping involved radiological protection practices.
In some controlled areas of the plant, yellow bags containing contaminated protective clothing were being stored.
These bags were not disposed of properly.
In other locations, articles of contaminated clothing were left inside a contaminated area on the floor because no receptacle was provided near the step-off pad to discard the used clothing.
In various locations, tools and extension.cords protruded from contaminated areas:
In many cases, it'as apparent that Radiological Protection management had not toured the area in quite a while.
Management attention appears necessary in this area.
The inspectors will continue to closely monitor housekeeping and radiological controls practices during subsequent inspections.
Review of Licensee Event
~Re orts ~LERs The LERs submitted to the NRC were reviewed to determine whether the details were clearly reported, the cause(s)
properly identified and'he corrective actions appropri'ate.
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 10CFR50.72 were applicable, and whether the requirements of 10CFR50.73 had been properly met.
(Note: the dates indicated are the event dates)
~ 1 Unit
a.
The following LER was reviewed and found to be satisfactory:
87-12, 07/24/87, Temporary Loss of Both Emergency Diesels.
7.2 Unit 2 a.
The following LERs were reviewed and found to be satisfactory:
86-05, Supplement 1, issued 4/6/87, Loading of 19 Fuel A'ssemblies in C quadrant with the SRM Channel C Bypassed.
86-12, Supplement 1, issued 3/25/87, Standby Gas Initiation-Supply Fan Trip ~
No discrepancies were noted.
8.
Three Mile Island Action Plan Items during 8.1 Unit 2 As a result of the Three Mile Island (TMI) plant accident, generic reactor enhancements were developed by the NRC.
NUREG-0737 documents the specific action requirements.
The following TMI issue was reviewed this inspection period:
Action Plan Item II.K.3.2.1 - Core Spray and LPCI A'utomatic Restart.
This NUREG-0737 issue identifies that core spray. and 'low pressure coolant injection ( LPCI) systems flow may be stopped by the operator and that these systems will not restart automatically on loss of water level if an initiation signal is still present.
The NRC staff concluded that the core spray and LPCI sy'tem logic-should be modified so that these systems will restart, if required, to assure adequate core cooling.
The inspector reviewed the licensee's response to this action plan item as documented in section 1. 10 of the Final Safety Analysis Report.
The licensee has taken a position, supported by both the BWR Owners Group and the General Electric Co., that an automatic restart of the LPCI and low pressure core spray systems should not be incorporated in the system logic.
However, the licensee did modify the high pressure core spray (HPCS)
system logic to provide for the automatic restart function.
The'nspector reviewed surveillance test procedure N2-0SP-CSH-R001, HPCS System Functional and Response Time Test, Revision 1, October 1986, and verified that the automatic restart function was incorporated in the HPCS system logic and is periodically tested.
The inspector also discussed the test procedure with licensee representatives and confirmed his understanding of this specific system design feature and its operatio This TMI Action Plan Item is closed.
9.
Licensee Action on IE Bulletins The inspector reviewed licensee records relating to the IE Bulletins identified below to verify that:
the IE Bulletins were received and reviewed for applicability; written responses were provided, if required; and the corrective action taken was adequate.
9.1 Unit
a.
IE Bulletin 79-27, Loss of Non-Class 1E Instrumentation and Control Power System Bus During Operation.
This bulletin was reviewed in Inspection Report 50-220/83-01 and left open pending completion of an evaluation of the loss of Instrument and Control Bus 130 and loss of the 125VDC buses.
The inspector determined that this evaluation has not been completed by the licensee.
This bulletin remains open and will be reviewed in a future report.
b.
IE Bulletin 80-25, Operating Pr'oblems with Target Rock Safety-Relief Valves at BMRs.
The inspector reviewed the licensee response dated May 19, 1981, which states that no valves manufactured by Target Rock are in use at Nine Mile Point Unit 1 and, therefore, that the actions of IE Bulletin 80-25 were not applicable.
The bulletin contains three specific actions which were not individually addressed by the licensee:
Action 1 addresses requirements which are specific to Target Rock safety-relief valves.
These requirements do not apply to Nine Mile Point Unit 1.
Action 2 requires that in the event a safety-relief valve fails to f'unction as designed, except for pressure setpoint requirements, and if the cause of the malfunction is not clearly understood, regardless of make or model, than standard operating procedures shall require the enti re valve be removed from service, disassembled, inspected, adjusted, and pressure setpoint tested with steam for proper operation prior to returning the valve to service.
The bulletin further requires that appropriate changes are made to licensee operating procedures to include the above requirements.
The licensee currently'as no such provisions in operating or maintenance procedures.
This item is considered applicable to Nine Mile, Point Unit 1 and the licensee's response, dated May 19, 1981, is incomplete since it does not address the requirements of Action Action 3 requires a review of the safety-relief valve pneumatic
'upply system..Nine Mile Point Unit 1 utilizes Electromatic
.Safety Relief valves which do not have an associated pneumatic supply.
Therefore, Action 3 is not applicable to Unit 1.
In summary, the licensee's response to Bulleti.n 80-25 is incomplete and requires revisions This bulletin will remain open pending inspector review of licensee action and a revised response.
10.
~Desi n Review
~Bass of Non-Essential Diesel Generator
~Tri s
During preoperational testing a Limerick Unit 1, a loss of 'electrical power resulted in a diesel engine tripping upon manual reenergization of an associated instrument power bus.
The cause was attributed to a
'non-essential diesel engine trip which is bypassed on a loss of coolant accident (LOCA) signal, but not a loss of offsite power (LOP).
The inspectors reviewed the Unit 1 and 2 emergency diesel generator start logics to determine if this problem could happen at Nine Mile Point.
10.1 Unit
Review of the FSAR and interviews with licensee representatives revealed that Unit 1 emergency diesel generators (EDGs)
do not have non-essential trips.
Consequently, there is no need to have a
LOCA or a LOP trip bypass function.
10.2 Unit 2 Interviews of the test engineer, review of.logic prints and review of the FSAR indicate that all three EDGs have non-essential trips that are bypassed under LOCA or LOP conditions.
Testing of the non-essential trips and the LOCA and LOP trip bypass functions was performed during preliminary ci rcuit logic testing and EDG preoperational testing.
The non-essential. trip bypass functions were verified by the licensee to operate properly.
11.
~Hana ament
~Neetin On August 19, 1987, Region I management met with licensee senior management on site to discuss the progress of the licensee's Self-Assessment Team (SAT) efforts.
The licensee presented
'a brief overview of the SAT Charter and team member inspection methodology and then summarized their findings and assessments, to date.
The licensee indicated that the final phase of their self-assessment efforts was just beginning.
They planned, in the following weeks, to review the SAT member findings, as a whole, and to assess any programmatic or management weaknesses or deficiencies.
Recommendations would be developed for those areas needing improvement'.
The NRC inspectors discussed some of their observations and preliminary assessments with members of the SAT Oversight Committee at the conclusion of the meeting.
The Oversight Committee is comprised of senior licensee management.
The licensee has periodically updated the resident inspectors of SAT findings throughout the inspection period.
12.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items or violations.
An unresolved item identified during this inspection is discussed in section 2.1.b.
11.
Exit ~Meetin s
At periodic intervals and at the conclus'ion 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 10 CFR 2.790 information.