IR 05000352/1985037

Insp Rept 50-352/85-37 on 850903-20.No Violation Noted. Major Areas Inspected:Startup Program During Test Condition TC-2,QA/QC Interfaces,Independent Measurements,Calculations, Verifications & Tours of Facility

ML20138D181
Person / Time
Site:	Limerick
Issue date:	10/16/1985
From:	Bissett P, Caphton D, Eselgroth P, Florek D, Kucharski S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20138D161	List: IR 05000352/1985037 ML20138D155
References
50-352-85-37, NUDOCS 8510230208
Download: ML20138D181 (12)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /85-37 Docket N License N NPF-39 Priority -

Category C Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name: Limerick Nuclear Generating Station

! Inspection At: Limerick, Pennsylvania Inspection Conducted: Septem_ber 3-20, 1985

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Inspector:: .

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s [O D. Flore a -React r Engineer ifate D.'

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' eni r Technical Reviewer 'date S.'

J L &n tor' Engineer

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at K charsk[i Re]

P.* Bissett, Reactor Engineer hn 3 12e : /Ddite /0/e-W Approved b : ..ap

1. P'. Eselgroth/phief, Test Progran Section

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date Inspection Summary:

Inspection on September 3-20, 1985 (Inspection Report No. 50-352/85-37)

Areas Inspected: Routine, onsite unannounced inspection of the startup ,

program during test condition TC-2 ir.cluding startup test witnessing of the major startup tests, shutdown from outside the control room and loss of offsite power and startup test results evaluation; licensee action on previous inspection findings; QA/QC interfaces; independent measurements, calculations and verifications; and tours of the facility. The inspection _ involved 145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br /> by four region-based inspector Results: No violations were identifie DR ADOCK O

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1.0 Persons Contacted

! l l Philadelphia Electric Company and Contractors

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• J.'Armstrong, Assistant Operations Engineer O. Atkinson, Lead Startup Test Coordinator  !

J. Doering, Operations Engineer i

• P. Duca, Technical' Engineer  !

G. Edwards, Engineer in Operations  !

. *C. Endriss, Regulatory Engineer P. Fleckser, Startup Test Scheduler f K. Folta, QC Site Supervisor  !

J. Franz,. Superintendent of Operations

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i J. Hutton, Engineer in Operations

A. Jenkins, Startup Test Program Supervisor  !

M. Held, QC Engineer

• G. Lauderback, QA Engineering j

, * Leitch, Plant Manager {

i J. McElwain, QA Auditor l

W. Reikito, Regulatory Coordinator  ;

• J. Rubert, QA Site Supervisor  !

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R. Smith, QA Auditor

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• Warren, Test Engineer  !

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U.S. Nuclear' Regulatory Commission '

t G. Kelly, Senior Resident Inspector l

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• J. Beall, Project Engineer i i

r j * Denotes those present at exit meeting on September 20, 1985. '

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i 2.0 Licensee Action on Previous Inspection Findings  ;

i (Closed) Inspector Follow-up Item (352/85-03-12). Revise appropriate

, procedures to. clearly state tagging requirements for weld rod ovens found '

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to be defective or out of calibration. The licensee has written and  ?

' implemented a new maintenance procedure, MA-??, " Maintenance Division  :

Administrative Procedure for Tagging of Defective Items," which includes '

the identification and. tagging of defective weld rod ovens. Also, weld  :

! rod' oven and portable rod heater procedure, Standard Work Instruction-17, was revised to reflect and reference MA-27. The inspector reviewed MA-27 ,i and discussed with the maintenance supervising engineer the changes that l were made to SWI-17. The -inspector had no further. questions following this review. This~ item is close l

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(Closed) Unresolved Item (352/85-09-01). Analyze the possible shutdown  !

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of all diesel generators due to a potential failure of the fire detection l system relative to time delay relay actuation time drift; electrical  !

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failures within the fire detection system; and component failures within  !

, the fire detection system as the result of either end-of-life or .

earthquake. The licensee initiated QA Finding Report N-498 which was  ;

forwarded to the Electrical Engineering Division for resolution. Follow- i ing an engineering evaluation of the above concerns, it was determined  !

that the failures in the fire detection system, noted above, would not  !

cause a common shutdown of all D/G' Engineering's response, which was i reviewed by the inspector with the licensee, indicated that 1) test data  !

j from Amerace Bulletin CR-1 revealed that the relays in question had a i repeat accuracy of 2%; 2) the circuit design precludes an electrical [

failure from af fecting more than one diesel generator; and 3) only a i sesmic event could cause simultaneous actuation of all three flow switches;  ;

however, the solid state timing circuit in the relay resets every time the i initiating circuit is opened due to chatte Therefore, the relay would l not time out to cause spurious trips of the diesel. Based upon the above ,

I review, this item is close The following items were identified as a concern by an NRC contractor during a technical review of the LGS AC and DC Electric Power Systems 1 conducted during the period of January 21-25, 1985. The results of this t

} review, as described in Brookhaven National Laboratory Technical Review Report, was forwarded to the licensee from Region I on March 25, 198 r

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(Closed)' Diesel Generator (D/G) Ventilation System. During a plant tour, i the contractor noted that none of the D/G ventilation fan and damper l indicating lights had permanent identification labels affixed to each i respective D/G ventilation panel. The licensee has since placed permanent '

labels next to each fan and damper indicating light. The inspector veri- l

fied that labels for each D/G fan and damper indicating light had been  !

l permanently affixed to D/G ventilation panels IAC563, 1BC563, ICC563 and 1DC563. Based upon the above review, this item is close I

! (Closed) D/G Emergency Service Water System (ESW). During the con-

tractor's review of the D/G supporting systems, the contractor noted  !

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that the required throttled position for the D/G ESW discharge valves (11-1005A,B,C,D), as listed in Procedure S.11.1A COL-1, differed from i those positions listed in S92.1.N COL- Upon a further review by the

. licensee, a determination was made as to the correct throttled position .

for the ESW discharge valves and the procedure checkoff lists were revised  !

accordingly. The inspector verified that D/G ESW valve positions listed  !

In Prccedure S.11.1A COL-1 agreed with Procedure S92.1.N COL-1. The l

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inspector, during a tour of the four diesel generators, also noted that i the ESW discharge valves were locked and tagged in the throttled positio !

Based upon the above review, this item is close [

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3.0 Startup Program References i

• . Regulatory Guide 1.68, Revision 2, " Initial Test Program for Water-Cooled Nuclear Power Reactors"

i * ANSI 18.7 - 1976, " Administrative Controls and Quality Assurance for l the Operational Phase of Nuclear Power Plants" l

i * Limerick Generating Station (LGS) Technical Specification i

• LGS Final Safety Analysis Report

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• LGS Safety Evaluation Report

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Specification NEB 0 23A1918, Revision 0, " Limerick 1 and 2 Startup

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Test Specification"

• LGS Startup Program Schedule 4 * Administrative Procedure A-200, "Startup Test Procedure Format and Content"

• - Administrative Procedure A-201, "Startup Test Procedure Control" i

Administrative Procedure A-202, "Startup Test Implementation" l *

Administrative Procedure A-203, "Startup Test Program Personnel 1 Training and Qualification" i

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3.1 Test Witnessing >

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1 The inspector witnessed portions of the preparation, conduct and j recovery of the following startup and hot functional test '

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HF-29, "Feedwater System Tuneup at TC-2" i

HF-27, " Pressure Control Outer Loop Tuneup at TC-2" i

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STP-22.1, " Pressure Regulator Response-Control Valve Operations" j

• STP-26.2, " Relief Valve Rated. Pressure Test"

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STP-27.1, " Turbine Trip Within Bypass Valve Capacity"  ;

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STP-28.1, " Remote Reactor Shutdown to Hot Standby" l

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* STP-28.2, " Remote Reactor Cooldown Demonstration" i

• STP-31.1, " Loss of Turbine Generator and Offsite Power" The tests were witnessed for the attributes identified in Inspection Report 50-352/84-74 in Section 2.2.

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Discussion f

i On September 4-5, 1985, the inspector observed hot functional test No. 29 being performed on feedwater pumps B&C. Adjustments were made to reduce level oscillations when subjected to step changes. No problems were identified during single element con- t trol; however, during the final run made in three element control i on September 5, 1985, the damping, although convergent, was less  ;

than desired. The decision was made to go to the next hot functional i test and pick up this problem at a later time in the testing sequenc I

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Pressure control tune up per hot functional test HF-27 was witnessed

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on September 5 and 6, 198 No problems were observed during the [

testing witnesse > ,

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Portions of STP 22.1 were witnessed on September 6, 198 No problems

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were observed during the testing witnesse ;

t On September 6, 1985, the inspector observed the safety' relief valve [

, (SRV) testing at rated conditions. Test personnel briefed plant  !

i operations on the conduct of the tes Expected plant performance l l

as well as potential problems that could occur were also discussed '

prior to the test. Prerequisites sampled by the inspector were i satisfie The licensee was also observed to monitor suppression  !

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pool temperature during'this test. Senior licensee management were  !

in the control room as well as QA/QC personnel during this tes !

After the first SRV lift (1835 hours0.0212 days <br />0.51 hours <br />0.00303 weeks <br />6.982175e-4 months <br />), the test personnel did not  !

observe a response on the real time transient recorder printe j

Licensee suspended testing to troubleshcot this occurrence. The test F personnel discovered that due to the large sampling plan required for [

vibration data, the real time printer lagged behind real time a few i minutes. This presented no further problems and testing resume l The inspector observed that when a SRV was operated, generator i megawatt output decreased approximately 40 MWe and returned to the pre-SRV lift value when the SRV was closed. Acoustic raonitoring testing was also being performed during the SRV testing. The inspec-tor also noted that operations personnel were conducting surveillance .

testihi on the vacuum breakers during and after the SRV testing was  !

l completed to comply with technical specifications. No unacceptable

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conditions were noted.

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On September 7, 1985 at 0007 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, the inspector observed the i i licensee tripping the-turbine while at 22% power in accordance with  !

[ STP-27.1. The licensee conducted a comprehensive test briefing prior i

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to the test. As expected, the reactor did not trip during this tes The inspector observed that less than 7 turbine bypass valves were required to open following the turbine trip. At 0020 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, the turbine generator was back on the grid. No unacceptable conditions were note On September 11, 1985 at 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br />, the licensee conducted STP-2 The plant was already in shutdown due to an unanticipated reactor scram that occurred earlier in the da This test required taking the plant from 150 psig reactor pressure, cooling down, placing the shut-down cooling system in service and lowering reactor temperature by 50 F, all from the remote shutdown pane At 1150 hours0.0133 days <br />0.319 hours <br />0.0019 weeks <br />4.37575e-4 months <br /> on September 11, 1985, the licen.see began cooling down from 500 psig reactor pressure by use of RCIC in the condensate stor-age tank (CST) to CST flowpath and by opening steam drains. At 1327 hours0.0154 days <br />0.369 hours <br />0.00219 weeks <br />5.049235e-4 months <br />, the RCIC turbine tripped due to high indicated water level (+54"). RCIC used wide range' water level but the narrow range level sensors indicated water level in the normal range. At the lower pres-sures, wide range and narrow range have large differences. When this occurred, the licensee also noted that reactor water level on the remote shutdown panel also utilized wide range level and was pegged high. The licensee noted this difference and for this test stationed the shift technical advisor in the auxiliary equipment room to pro-vide the narrow range level informatio RCIC operation from the re-mote shutdown panel is not affected by the high water level indication since the high level RCIC turbine tr.ip is bypassed when the remote shutdown panel is utilized. The licensee further did not want to utilize the remote shutdown panel wide range level indication to con-trol level in the normal indicated range since, for this test, this level would initiate the reactor protection low water level trip During a situation which requires remote shutdown, however, this would not present a proble The remote shutdown panel was manned at 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br />. RCIC was operated and SRV actuation was utilized to cool down the plant. The licensee also had the required operating crew in.the control room to monitor

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plant performance and to take over control, if the remote shutdown

panel was unable to do so. RCIC initially was operated with vessel

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injection and then was transferred to the CST to CST flowpath. After several SRV lifts to cooldown, vessel inventory required replenishment to restc,re water level; the only other source of water during this

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evolution was from the control rod drive (CRD) system (~50 gpm).

RCIC was being realigned to transfer water from the CST to the vessel;

! however, the injection valve could not be opened from the' remote shut-

down panel. .The licensee attempted to operate the valve locally but i

was unable to do so. The licensee evaluated the situation and secured the RCIC from CST to CST operation and attempted to.open the valve manually. The licensee was able to manually open the valve suf-ficiently to allow the remcte operator to open it the ro t of the wa During this period, flow from the CRD system restored normal level

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! without any need for RCIC. The licensee then jointly operated RCIC i i in the vessel injection mode and SRV to cooldown to the point at I which shutdown cooling could be placed in service. This was accom- I plished and a 50*F cooldown was demonstrated. The test was then ter- [

j minated and control was restored to the control room at 1935 hour0.0224 days <br />0.538 hours <br />0.0032 weeks <br />7.362675e-4 months <br /> L i Throughout the test, the licensee was very thorough in assuring that i information on plant status in the remote shutdown areas was obtained

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from instrumentation outside the control room only. The test demon- .

l strated that.the plant can be cooled down and placed in shutdown cool-  !

ing from the remote shutdown panel and also demonstrated modifications  !

I to the procedures and remote shutdown panel area to enhance the abili- l i ty to shutdown from the ramote shutdown panel. Included are the water

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level indications, key control provisions, need for P&ID's in the

remote shutdown area and minor. sequence changes.in the procedur j The licensee was recording these observations as they occurred and j

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the licensee planned to address them. The inspector will review the  !

licensee actions in a future inspectio On September 12, 1985, the licensee performed a reactor scram and [

L; MSIV isolation and began a controlled reactor cooldown, as described j

! in STP-28.1, from the remote shutdown areas. The control room was i evacuated at 1842 and reactor scram occurred at 1844. All control i i

rods were inserted. The reactor cooldown was initiated at 1856 hours0.0215 days <br />0.516 hours <br />0.00307 weeks <br />7.06208e-4 months <br /> i

! and terminated at 1932 hours0.0224 days <br />0.537 hours <br />0.00319 weeks <br />7.35126e-4 months <br /> and satisfied the test requirements. No  !

, unacceptable conditions were note !

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j On September 16, 1985, the licensee performed STP-31.1, " Loss of Tur-

{ bine Generator and Offsite Power." The reactor was at 20.8*.' power i prior to the test. Inspectors were stationed in the control room and i l at the diesel generators. After the start of all diesel generators,  !

inspectors toured various elevations of the reactor and control build-  :

! ings for lighting levels. At 1752 hours0.0203 days <br />0.487 hours <br />0.0029 weeks <br />6.66636e-4 months <br />, the test was initiated by a [

! turbine trip and isolation of the offsite sources of power. Because -

the plant was within the bypass capacity and uses inverters for the  !

RPS power supply, a reactor scram does not immediately occur. The j inspector observed diesel generator operation within 10 seconds. Be-l tween 5 and 6 bypass valves controlled reactor pressure. At approx- {

' imately 58 seconds into the event, the inspector observed a reactor  !

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scram occurred on low level. All rods inserted. No safety relief j valves were required to o:erate and bypass valves closed. At approx-  ;

imately 23 minutes, High Pressure Coolant Injection (HPCI) auto ini- i

tiated on low level. Reactor Core Isolation Cooling (RCIC) was manu- l ally started and HPCI secured to contral reactor cooldown. At approx-  ;

imately 25 minutes, the Main Steam Isolation Valves (MSIV) automati-

, cally shut. The diesel generators were observed to run for the thirty i minutes required in the procedur During the plant tours conducted

! during the loss of power test, two areas were noted wherein lighting [

l levels were poor: 1) the 283 foot level near the hydrogen recombin- t i ers and the standby liquid control system and 2) the 313 foot level l l near the ventilation ducts. The licensee personnel were also l

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touring the plant for lighting level In a future inspection, the inspector will review the licensee plans regarding the plant lighting levels. No other problems were note ;

The inspector observed licensee preparations for the conduct of STP-28.1, 28.2 and 31.1. The licensee preparation was comprehensive

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and thorough. Prior to the test, walkdowns of procedures were

! conducted. Special procedures were developed to test RCIC operation and suppression pool cooling from the remote shutdown panel. The licensee had ar extra crew of operators and test personnel for the

! tests. Anticipated problems, both major and minor, were discussed

and reviewed with operations personnel prior to the tests. The

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simulato'r was used to train the speci.fic crews on the loss of power

, and other evolutions that could occur. Senior management personnel j were present in the control room for the conduct of the tests and i were effectively utilized to assist in the resolution of the RCIC

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valve problem during performance of STP-28.2. QA and QC personnel

were observed to be conducting surveillances during these tests. The licensee adequately addressed the inspector's questions in the prep-aration phase. The inspector also witnessed management review in a

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Procedures and Operations Review Committee (PORC) meeting on i September 3, 1985 wherein test procedure changes were reviewed and discussed for these tests. No unacceptable conditions were noted.

i On September 6, 1985, while witnessing an operator walkthrough and i

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simulation of operation from the remote shutdown panel, the inspector j questioned whether the recirculation system pump suction valve, which

was operated in Procedure SE-1, was contained in the licensee inservice testing program. The valve was not contained in Revision 5 j of the inservice testing program. The licensee representative indi-cated that SE-1 also indicates that if recirculation pump suction

, valve cannot be operated, the LPCI loop injection mode should be i utilize (Close HV-51-1F015A and open HV-51-1F017A.) The inspector

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reviewed letter J. Millard to D. Fetters, "RHR Shutdown Return Through the LPCI Injection Line," dated February 1, 1985 which analyzed this

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situation and the inservice inspection plan to determine if the valves I were include The licensee response and cocuments reviewed satisfied

, the inspector concern. No further questions were noted.

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1 s i 3.2 Test Results Evaluatien

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Scope The startup tests listed in the discussion section below were reviewed for the attributes identified in Inspection Report 50-352/84-70, Sec-tion 3.3. In addition, the inspector reviewed 89 test exception re-ports for technical adequacy and p'rocessing in accordance with the -

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Discussion Except as noted below, all startup test results were found to meet the attributes referenced above. A summary of each startup test follows. The test exceptions review were all found to be acceptabl STP-1.3 " Gaseous Effluent Sampling and Analysis," Revision 0, Test implemented August 15, 1985 One test exception was identified due to all data not being available. This will be obtained at a later dat STP-10.3 "IRM/APRM Overlap," Revision 1, Test implemented August 9, 1985 IRM/APRM overlap was verified except for APRM "C" which was inoperative during this test and will be tested separatel A test exception was prepared in accordance with the administrative procedur STP-11.2 "LPRM Calibration Without Process Computer," Revision 2, Test implemented August 14, 1985 Data were accepted by managemen Several LPRM's were bypassed and will be tested at a later date. Test exceptions were properly prepare STP-11.4 "LPRM Operational Verification During Rod Withdrawal,"

Revision 1, Test implemented August 14, 1985 Detectors tested responded satisfactorily to changes in neutron flu STP-13.2 "TIP Alignment at Rated Temperature," Revision 1, Test implemented August 12, 1986 This test was conducted to satisfy Test Exception Report TER-83. Test was acceptabl STP-13.3 " Program Testing at TC-1," Revision 1, Test implemented August 14, 1985.

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Data were accepted by managemen Test exceptions identi-fied were prepared per the administrative procedur STP-14.6 "First RCIC Cold Quickstart at Rated Pressure CST to RPV,"

Revision 1, Test implemented April 9, 198 RCIC did not trip and achieved rated flow into the vessel j in approximately 18 seconds and thus satisfied test

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SYP-14.6 "Second RCIC Cold Quickstart at Rated Pressure, CST to RPV," Test implemented April 12, 1985 RCIC did not trip and achieved rated flow in approximately 19 seconds and thus satisfied test acceptance criteri STP-14.7 "RCIC Surveillance Tests CST to CST," Revision 1, Test implemented August 25, 1985 RCIC achieved greater than rated flow and discharge pressure 70 psi greater than reactor pressure in 19 seconds thus satisfying the test acceptance criteri No divergent oscillations were noted. Test exceptions identified were processed in accordance with the administrative procedur STP-14.8 "RCIC Endurance Run," Revision 1, Test implemented August 15, 198 RCIC was verified to run continuously and thus satisfied the acceptance criteri STP-14.9 " Loss of AC Power - RCIC," Revision 1, Test implemented August 15, 198 Vessel injections were achieved in 18.3 seconds from initiation with RCIC achieving rated flow. All acceptance criteria were satisfie STP-25.1 "MSIV Functional Test," Revision 0, Test implemented August 16, 1985 Initial testing of MSIV 22A resulted in the valve closing too quickly - 2.84 second The valve was readjusted and tested satisfactorily. MSIV stroke times satisfied the test acceptance criteri MS1V Stroke Times MSIV A B C D Inboard 22 3.73 3.45 3.48 3.53 l

Outboard 28 3.85 3.71 3.58 14.08 STP-34.1 "Offgas Performance Verification," Revision 2, Test implemented August 15, 1985 Test criteria were satisfied.

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Findings No violations were note .0 QA/QC Interfaces '

QA has one site supervisor and seven lead auditor Certifications are per N45.2.23 - 1978 in accordance with Procedure QADP-14. One lead auditor is a certified senior reactor operato This lead auditor ,

participated in two audits, AL84-86PR and AL85-01PR, that were sampled '

during the inspection. Audits are planned and checklists are prepare During a review of checklists for startup testing audits, it was noted that the GE testing specification was not liste QA audit checklists will be revised to include the GE test specificatio The inspector observed use of the GE test specification by the QA person-nel during this inspectio QA/QC personnel were observed to be conducting surveillance testing during performance of HF-27, ST-28.1, 28.2, 26.2, and 31.1. A QC inspector and his supervisor were interviewed. QC certifications were reviewed. QC surveillance reports were also reviewed. No problems were identifie .0 Independent Measurements, Calculations and Verifications during the course of this inspection, the inspector independently veri-fied, on a sampling basis, the prerequisites contained in the startup tests witnesse The inspector also independently measured the major plant response times (RpS actuation, HPCI initiation, MSIV closure) during the loss of power test and verified that the test was performed for at least thirty minute The inspector also independently verified several of the analysis steps in completed test procedures using the data collected during the test as part of the test result evaluation .0 Plant Tours The insoector made several tours of the facility during the course of the inspection and specifically during the loss of power test including the reactcr building, turbine building, control structure, control building and diesel generator building. Observations of lighting levels during the loss of power test are described in Section No other unacceptable conditions were noted.

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7.0 Exit Interview An exit meeting was held on September 20, 1985 to discuss the inspection findings as detailed in this inspection report. (See Paragraph 1 for attendees.) At no time during the inspection did the inspector provide written inspection findings to the licensee. At the exit, the licensee did not identify any proprietary material that was contained within the scope of the inspectio t-

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