IR 05000213/1990012
| ML20059E668 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 08/22/1990 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20059E663 | List: |
| References | |
| 50-213-90-12, IEB-79-18, NUDOCS 9009100270 | |
| Download: ML20059E668 (53) | |
Text
{{#Wiki_filter:1 .. t g . . . . . . i U.S. NUCLEAR REGULATORY COMMISSION i REGION I.
Report No.
50-213/90-12 License No.
DPR-61 Licensee: Connecticut Yankee Atomic Power Company ' P. O. Box 270 Hartford, CT 06141-0270 , Facility: Haddam Neck Plant Location: Haddam Neck, Connecticut Inspection Dates: June 21, 1990 through July 31, 1990.
Reporting Inspector: JohnT.Shediosky,SeniorRes'identInspec$or
Inspectors: Andra A. Asar.,, Resident Inspector . James E. Beall, Senior. Resident Inspector, Beaver Valley Peter J. Habighorst, Resident Inspector, Millstone Unit 2 Kenneth S. Kolaczyk, Resident. Inspector, Millstone Unit 3 Frederick P. Paulitz, Electrical Engineer, NRR/ DST /ICSB Leonard J. Prividy, Senior Reactor Engineer,-DRS John T. Shedlosky, Senior Resident -Inspector David M. Silk, Operations Engineer, DRS '
Anton Vegel, Reactor Engineer, ORP i Alan B. Wang, Project Manager, NRR/PD I-4 ,
d [/ [/23/4 0 Approved by: ~ DonaldR.Haverkamp,Chif Date P,eactor Projects Section 4A Division of Reactor Projects Inspection Summary: Inspection on June 21,_1990 - July 31, 1990 > (Inspection Report No.150-213/90-12) Areas Inspected: Routine safety inspection by the resident. inspectors. Areas , reviewed -included the-review of the final refueling outage activities, the preparations for reactor startup, examinations of safety related equipment , t readiness, review of the containment integrated leak rate test, review of operational events, radiological controls, maintenance and surveillance ' activities, and special safeguards system electrical testing. A review was conducted of electrical system modifications implemented during this outage.
Results: See Executive Summary i 900910027ADOC.y,hk13 PDR PDC Q .
< , . - ! ,4 . Executive Summary Plant Operations: Several problems were experienced.in the implementation of revised technical' specifications (RTS).
Plant heatup was restricted because of a conflict concerning the ability to perform auxiliary feedwater pump capacity tests.
Also, the reactor entered Op' rational Mode 3 with main steam line flow e - instrumentation out of service due to the use of calibration practices which~ were not compatible with RTS. Although this constitutes a violation of technical specifications, enforcement discretion is being taken because this was licensee identified and of minor safety significance in that the main . steam isolation valves remained closed.
The NRC issued a temporary waiver of compliance regarding the AFW pump. test;-the steam line flow instrument issue was corrected shortly af ter d* scovery.
Radiological Controls: i Good radiological controls were in practice.
However, due to the extended
outage duration-and additional work items, the licensee's goal for total _' exposure for the year (392 person-REM) is' being approached (now 373).
Maintenance and Surveillance: Extensive. tests were conducted of th'e recently modified electrical distribu-tion system and plant instrumentation. 'These tests provided final acceptance for the modifications which were made to-comply with 10 CFR 50,. Appendix R and also to correct several previously identified single failure issues.
A.
containment integrated leak rate test was successfully conducted.
Security and Safeguards: Good security performance was noted during this; inspection. period.
Engineering and Technical Support: .. . A postulated accident condition was discovered in which the "B" emergency diesel generator electrical load could exceed the value to which the. machine was periodically tested.. A test confirmed the diesel generator's ability to operate at the higher load.
. The potential was discovered for original plant. equipment Westinghouse Type FA and HFA molded case circuit breakers to open because of their closing toggle failing to fully reposition.
Safety Assessment and Quality Verificationi The review of the readiness for reactor plant heatup was conducted by all levels ~of site personnel and discussed in. detail at planning meetings.
This was observed to be a good practice.
Several previously identified unresolved items were. closed.
These concerned the verification for full closure of core deluge motor operated valves (87-22-05), completion of the audibility survey of evacuation alarms (Bulletin 79-18) and the trip set points of Westinghouse.
' Type HMCP motor circuit protection devices (90-08-02).
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. < .. .+ . , = . TABLE OF CONTENTS- . Page 1.
' S umma ry o f Fa c i l i ty Act i v i t i e s.................... 1-2, Plant Operations (71707, 71710,- and 93702)* .. :......... I 2.1 Operational Safety Verification................. .1 2.2 EngineeredLSafety Features System Walkdown.....-........
2.3 Follow-up of Events occurring During the Insa ction.
Period...........................
. 2.3.1 Reactor Coolant System Cooldown in Excess of-Administrative Limits,....
- 3
...,_... '..... 2.3.2 Inoperable Main Steam Line High Flow- , Instrumentation,......... .=,
i ....... .. 2.3.3 Temporary-Waiver of Compliance Relating to' , Testing of'the Auxiliary Feedwater. Pumps
....... 2.3.4 Potential for Overload of'the "B" Emergency , Diesel Generator... .c.
.: 6, ............. 2.3.5 Potential for Westinghouse Type FA and-HFA. Molded' j.
' Case Circuit Breakers to Inadvertently Open'.......
! 3.
Radiological Controls (71707).........,..._..-....-.
4.
Maintenance and Surveillance (61726, 62703, 70313, and 71707)...
4.1. Maintenance Observation '8 ' ................... 4.2 Surveillance Observation.............., ...
4.2.1 Plant Integrated Electrical Tests............. 10.
j 4.2.2 Auxiliary Feedwater Pump Flow Capacity Test.
~ ' ..,... 4.2.3 Containment Integrated Leak Rate Test......_,
..... 4.2.3.1 Test Procedures-13 .................. 4.2.3.2 Test Conduct. 13- ' ...........-,..,..... 4.2.3.3 Test Observations
................. 4.2.3.4 Test-Results....................
4.2.4 Local Leak Rate Testing of the Containment ' Spray Penetration-
...........,....... , S.
Security (71707)
.......................... i 6.
Engineering and Technical Support (37700, 37828, and 71707)....
1 6.1 Emergency Diesel Generator Load Analysis........
.... 6.2 Installation of New Containment Isolation Valve
....... 6.3 Electrical-Modifications...................
6.3.1-Background
........... ........... 6.3.2 Purpose......................... 20 6.3.3 Scope
.........................
iii ' A
. ... .. a . 6.3.4 Findings and Conclusions 20- ....,........-.... 6.3.4.1 Design Change Process
............... 6.3.4.2 Drawing Control...................
6.3.4.3 Updated Final Safety Analysis Report Review
.... 6.3.4.4: Engineering Support
................ 6.3.4.5 Design Changes
............... .. 6.3.4.6 Problem Reporting and Corrective Action
....... 6.3.4.7 Security and Tornado Protection
........... 7.
Safety Assessment and Quality Verification (40500,.71707, 90712, and 92700)..................... .. 30-7.1 Plant Operations Review Committee and Nuclear Review Board..
7.2 Review of Written Reports
,.............,... 7.3 ' Follow-up of Previous Inspection ~ Findings ...........
7.3.1 Full Closure of Core Deluge Motor Operated Valves.v.
32- .. 7.3.2 Bulletin 79-18,. Audibility of Evacuation Alarms in High Noise Areas '
.......... ...... -... 7.3.3 Trip Set Points for Type HMCP Motor Circuit Protection Devices ..
33
.....-,......... 8.
Exit Interviews (30703)
... .......-, .........
- -
The NRC Inspection Manual inspection procedure or temporary instruction that was used as inspection guidance is listed for each applicable report section.
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.- _,e . .. . DETAILS 1.
-Summary of Facility Activities This was the eighth _ routine resident inspection-during'the 1989/1990 refueling and maintenance outage.
During this inspection period the 'eactor was reassembled _ and the transition made from Operational Mode 6 5 on June 23. A extensive integr~ated test was made of.the plant: wergency core cooling equipment during the period of June 25 through 28 j and a containment integrated leak rate test _was conducted July'3 through ,! July 7.
The reactor temperature was increased into Operational Mode' 4 and remained there from 8:00 p.m. on July 21 unti1= 3:07 p.m. on July 23 , for a routine hydrostatic test of the' reactor coolant system.
Following l that test, the plant was returned to Mode 5 to allow for minor repai 5 i including valve stem ' repacking and adjustments. After these routine maintenance actions, a second plant heatup'was conducted.
The reactor was placed in Operational. Mode 4 at.5:33 p.m.' on July 25; and Mode 3~at 1:13 a.m. on July'27.
The NRC Office of Nuclear Reactor Regulation issued a temporary waiver of compliance to a technical specification surveillance requirement relating i to the turbine driven auxiliary feedwater pumps at 5:25 p.m. on July 26.
Specifications requirements 4.0.4'and 4'7.1.2.2 required a successful- ' - test of pump capacity to demonstrate system operability.
Th'< s.uxiliary feedwater system is required to be operational in Modes 1, 2 and 3.
However, the reactor coolant system must be~near normal operating i temperature ard pressure (535 degrees F and 2000 psig) to provide ! sufficient steam energy to the pump turbine drive.
The licensee applied i for a revision to the surveillance specification along.with a ' temporary l waiver of compliance by letter dated July 26, 1990. The waiver permitted i plant heatup to continue in support.of test' performance.
The request for.
'! the technical specification amendment is under consideration.
The licensee applied for a second waiver of compliance to specification j 3.7.1.2 on July 31. At that time it appeared that a plant cooldown to I Operational Mode 4 would be required without sufficient time to investi-l gate the auxiliary feedwater pump performance deficiencies.
Several_ j unsuccessful attempts were made to complete the pump performance tests.
! Although the licensee applied for and was verbally granted the waiver by
- 1 the NRC Region I Office, the application was withdrawn by the'. licensee t
after the effects of new turbine speed gcvernor settings were determined and corrective actions taken, ig 2.
Plant Operations j 2.1 0_perational Safety Verification l The inspectors observed plant operation and verified that the plant was operated safely and in accordance with licensee procedures and regulatory requirements.
The regular tours conducted by the ' i I c a
. l .. -.
i . resident insp<ctors were augmented by-a team of' visiting inspectors.
-The following plant' areas were covered: control room security access point -- -- primary auxiliary building protected-area fence- -- -- ' radiological control poir,t intake structure -- -- electrical switchgear rooms diesel generator rooms -- -- auxiliary feedwater pump room turbine building -- -- Control room instruments and plant computer indications were ob-q served for correlation between channels and for conformance with plant technical specification.(TS) requiremer.ts..0perability of engineered safety _ features. other safety related systems and on-site and off-site power s'ources were verified.
The inspectors observed various alarm conditions and confirmed that operator response was in accordance with plant operating procedures.
Routine operations ! surveillance testing was also observed.
Compliance with TS limiting ' conditions for operation and implementation of' appropriate action ! statements for out-of-service equipment was inspected.
Plant-radiation menitoring system ind.ications and plant stack effluent
monitor recordings were reviewed for unexpected changes.
Logs and records were reviewed to determine if entries were' accurate and identified equipment status or deficiencies.
These records included operating logs, turnover sheets, system safety tags, and'the jumper- ' and lifted lead book.
Plant housekeeping controls were monitored, i including control and storage of flammable material-and other potential safety hazards.
The inspectors also examined the condi- ! tion of various fire protection, meteorological,-and seismic moni - e toring systems.
Control room and shift manning was compared to regulatory requirements and portions of shift turnovers were ob-served.
Control room access was properly controlled and a'profes-sional atmosphere maintained.
In addition to normal ~tility working hours, the review of plant u operations was routinely conducted during portions of backshifts (evening shif ts) and deep backshifts (weekend ' nd -night shifts).
a Inspection coverage was provided.for 102 hours during backshifts and 61 hours during deep backshifts.
Operators were alert and displayed . no signs of inattention to duty or fatigue.
' 2.2 Engineered Safety Features System Walkdown In addition to routine observations made during regular plant tours, the inspectors conducted walkdowns of.the accessible portions of selected safety related systems.
The inspectors verified system operability through reviews of valve lineups, control room system ' prints,-equipment conditions, instrument calibrations, surveillance test irequencies and results, and control room indications.
During this f nspection period, walkdowns of the fdlowing systems were perfvrmed:
e " .. .
.. , 'AuxClary Feedwater --
Ren dual Heat Removal ' -- Service Water -- - High Pressure Safety Injection Emergency Diesel Generators -- 4160 and 480 volt a.c. ' safety related electrical. distribution -- 320 volt.d.c. safety related distribution -- , No significant observations were-made.
2.3 Follow-up of Events Occurring During the Inspection Period During the inspection period, the-inspectors provided on-site cover-age.and follow-up of unplanned events.
Plant conditions, alignment _- of safety systems, and licensee actions were reviewed. -The inspec-tors confirmed that required notifications were made to the.NRC.
During' event follow-up, the inspectors reviewed the corresponding-- i plant information report (PIR) package, including the event details, root cause analysis, and corrective actions taken to prevent recur-rence. The following events were reviewed: 2.3.1 RCS Cooldown Rate in Excess of Administrative Limits On July 23, the procedural limit for: reactor coolant system (RCS) cooldown rate was exceeded, however, the technical specification (TS) requirements for cooldown rates were not violated. Operators took immediate actions.to decrease the cooldown rate but this necessitated a plant configuration which deviated from the applicable procedures.
Following the RCS hydrostatic test, a plant cooldown was l ~ performed to permit repair of several. identified system-t leaks.
The cooldown was being conducted in accordance with l the applicable portions of Normal Operating Procedure (N0P) 2.3-4, " Shutdown from-Hot Standby to Cold Shutdown." The residual heat removal-(RHR) system was-placed in. service'per NDP 2.9-1, " Placing RHR in Service", and (in accordance with this procedure) a component cooling water (CCW)Lflow of 1500-gallons per minute (gpm) was established. for eech RHR heat exchanger.
Shortly thereafter, a reactor' coolant pump was, secured. When RCS temperature decreased to 200 degrees F, mode 5 was reentered.
NOP-2.3-4 redefines the administrative cooldown rate limit in mode 5 to.20 degrees F/ hour; this provides sufficient margin to the TS 3.4.9.1 limit of 30 degrees F/ hour.
With negligible decay heat, no reactor coolant pump heat and system cooling by CCW, the RCS cooldown rate increased to 22.8 degrees F/ hour between 3:16 p.m. and 4:16-p.m.
I Operators immediately reduced CCW supply to the RHR heat exchangers to about 500 gpm.
The cooldown rate was reduced
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'4L , i , to within pr.ocedural lieits.
However, in this condition, the CCW flow to RHR was not la accordance with.NOP 2.9-1.
Station management was infarmed of this discrepancy and a Plant Information Report wns initiateo.
, The RHR pump seal cooler water supply is from the CCW flow to - the RHR heat exchangers.
TFe 1500 gpm CCW-flow limit was- _ established to ensure sufficient pump seal cooler flow. An engineering evaluation to support reduced CCW flow between RCS temperatures of 200 degrees F and-140 degr::: F was not available.
However, with the RCS bsley! 140 degrees F, reduced CCW flow is acceptable.
A temporary procedure change' . to NOP 2.9-1 was prepared and approved to permit tne reduced-CCW flow below 140 degrees F.
. An engineering evaluation is being conducted to determine acceptable CCW flow rates to the-RHR' system with reduced RCS-temperatures, t ' The inspector observed control room operations during this
evolution and attended the Plant Operations Review Committee
meeting which discussed this event and approved the procedure-change.
There were no unac:aptable conditions identified.
. 2.3.2 Inoperable Main Steam Line High Flow Instrumentation The licensee discovered on July 27 at 9:50' p.m. that entry-i had been made into Operational Mode 3 from Mode 4 earlier that day without the required main steam line flow .
instruments being operable.
These instruments are required.
' - by Technical Specification (TS) 3.3,2 and Table 3.3-2 Item No. 2 for main steam line break detection logic. All.four' main steam isolation valves remained closed during the time the reactor was in Mode.3.
The high flow instrument channels were being used to provide test data on isolated steam generator pressure'to support the calibration of reactor coolant system (RCS) resistance temoerature detectors (RTDs).
It had been a routine practice in the past to perform the calibration in this manner.
The evolution had been controlled under surveillance procedure .a SUR 5.2-15, " Reactor Coolant System Resistance Temperature Detector Isothermal Test", Revision 10, dated June 3, 1990.
. Revised technical specifications, which were issued on April 26, 1990, required _these instruments for Operational _ Modes 1, 2 and 3 whereas the previous specification only required the instruments during power operation. The fact that SUR 5;2-15 removed the main steam line high flow instruments from 'l I
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> ,. ,j-5 . - i t c service and that they were required for entry sinto Operation- , al Mode 3 by the revised TS apparently escaped the licensee's reviews.
The reactor entered Mode 3 at 1:13 a.m. on July 27.
Upon discovery of the error the instruments were placed in the tripped condition.
The licensee will address the long term-corrective actions within a_ Licensee Event Report. An immediate notification was made in accordance with the requirements of 10 CFR 50.72(b)(2)(11).
The entry into Mode 3 without the required main -steam line high flow instruments being operable was licensee identified _ and of minor safety significance in that all four main steam line isolation valves remained' closed.
Immediate corrective actions were taken to place.the instrument channels in the tripped condition. Although the failure to_ have the required' instrumentation channels operable constitutes a violation of-TS, no Notice of Violation is being issued in accordance with the provisions of 10 CFR Part 2, Appendix C, Section V.G.1, Exercise of Discretion (NC 90-12-01).
l t 2.3.3 Temporary Waiver of Compliance Relating to Testing of the-Auxiliary Feedwater Pumps The NRC Office of Nuclear Reactor Regulation issued a ' Temporary Waiver of Compliance relating to surveillance testing necessary to. demonstrate auxiliary feedwater system operability on July 26.
The waiver concerned the Technical Specification (TS) 4.0.4 restriction of entry into ~ i Operational Mode 3 based on pump operability demonstratior, ] required by TS 4.7.1.2.2.
Both pumps had not been successfully tested within the past eighteen months as required by TS_4.7.1'.2.2.
Because the pumps are steam turbine driven, the testing is performed with ! the reactor coolant system near normal operating temperature , and pressure.
This test was normally conducted-during plant shutdown prior to a refueling outage.
However when-performed in September, 1989, the "A" AFW pump failed to developed sufficient flow.
Additionally, the technical specification in effect at that time did not prohibit a plant heatup to normal operating' , temperature without successfully completing this test. The i specifications were revised by NRC letter dated April 26',.1990.
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. This restriction was removed by the NRC with the Temporary Waiver of Compliance.
Complete details of this issue are addressed in a licensee letter to the NRC dated July 26, 1990 ' containing the application for amendment of the operating-license and in the NRC response which is dated July 27,1990.
There were no unaccepteble; conditions identified.
! 2.3.4 Potential for Overload of the "B" Emergency Diesel Generator The inspector. reviewed the licensee's actions following the discovery of a more limiting load profile for-the "B" emer-gency diesel generator;(EDG) than previously analyzed.
This problem, which is discussed in Section 6.1 of this report, was found to occur in the combination of a loss of coolant accident, loss of off site power and the failure of the "A" EDG, The new peak load was found to be 2915.'35kw.
This level of loading was determined to potentially exist for up to 12 minutes.
' The resulting load was from the combination of automatically swuenced and manually started equipment. Although within the capacity of the diesel generator, it exceeded.the load value to which the diesel generator was periodically tested, 2850kw.
Based on this concern, the "B" EDG was run at' 2950kw' for ~ 15 minutes on July 13.
There were no unacceptable conditions identified.
2.3.5 Potential for Westinghouse Type FA and HFA Molded Case-Circuit Breakers to Inadvertently Open The licensee discovered-the potential for a defect in origi- ~ nal plant equipment Westinghouse Type.FA and HFA molded case circuit breakers. The operating mechanism was found not to i toggle properly on several breakers to date during 1990.
The
breakers were found to reopen as the person.operatingtit released the hand lever.
. The licensee assigned individuals knowledgeable of the.
problem to manually cycle all of-the remaining ~ Type FA and HFA breakers.
All defective or potentially defective break- , ers were replaced with new replacement devices. These replacements were Type.HFB molded case circuit breakers or Type HMCP motor circuit protectors.
Failed breakers assigned to scrap were examined to determine the nature of the defect. 'It appeared that the spring loaded snap mechanism was failing to toggle and. hold the breaker in -
' , y a.
. a closed position.- The cause was probably a combination of- ' wear,. dust and dry lubricant. A'small amount of commercial- ' spray electronic cleaning solvent appeared to correct the problem.
However, defective breakers.or breakers opened for-examination were not' reused.
There did not-appear to be any defects with the' breaker over current trip mechanism.
Because of concerns that all defective breakers may not be-l found by the. inspection technique of manually cycling-the ' snap switch, the licensee decided to implement temporary ) corrective measures pending the replacement-of all safety-re?ated Type FA and HFA circuit breakers.
Based on engi-- neering' analysis of the problem, the 1.icensee.made use of the-mechanical latch p:ovided on the breaker manual-operating handle.
That latch is' used for locking the breaker handle in either the open or closed position.
Since the breaker..was (asigned to be a trip free device as. required by Underwriters Laboratory Standard 489,~ the manual operating handle was pinned-in the closed position if the breaker was required to be in that condition.
The; licensee confirmed with a manufac-turers representative that the breaker would operate properly and trip open on overload or.. fault current.
Each safety related-Type FA and HfA breaker was provided with , a special pin device which would engage the manual operating handle position lock.
The operators-were' instructed as to-the purpose of thess devices; the pins were controlled through the station jumper and bypass administrative system, It appeared that sufficient instruction was.given to the operations personnel as to prevent any confusion as to their authority to operate the breaker.
The inspector reviewed the safety evaluation which substanti-ated this action.. Verification was made that any defective
breakers were replaced and that locking pi.ns were placed on the. remaining breakers. There were no unacceptable condi-tions identified.
3.
Radiological Controls
During routine inspections of the accessible plant areas, the inspectors observed the implementation of selected portions of the licensee's radiological controls program.
Utilization and compliance with radiation work permits (RWPs) was reviewed to ensure that detailed descriptions of radiological conditions were provided and that personnel-adhered to RWP requirements.
The inspectors observed controls of access to various radiologically controlled areas and the use of personnel monitors and frisking methods upon exit from those areas.
Posting and control of radiation areas, contaminated areas and hot spots, and labelling-and , l control of containers holding radioactive materials were verified tr be l: ! , ,
.. . I I
. i in accordaace with. licensee procedures.
During this' inspection period,
routine radiological controls were observed.
Health physics technician control and monitoring of these activities were determined to be adequate.
The extended length of the outage along with the increased secpe of work has resulted in additional unplanned personnel radiation exposure. As~of.
the end of the report period, 372.97 person Rem had been expended for the I year to date.
This is 95.15 percent'of the licensee's 392 person Rem goal of the year.
! i There were no unacceptable conditions identified.
' 4.
Maintenance and Surveillance 4.1 Maintenance Observation j The inspectors observed various corrective and preventive mainte - nance activities for compliance with procedures, plant technical specifications, and applicable codes and standards.
The inspectors also verified the appropriate qutlity services: division.(QSD) involvement, use of safety tags,. equipment alignment and use of -
jumpers, radiological and fire prevention controls, personnel . ! qualifications, post-maintenance testing, and reportability, portions of activities that were reviewed included: Troubleshooting of boron injection path check valve (BA-CV-387) -- flow blockage;- Charging pump auxiliary lubricating oil pump breaker installa- -- tion; . Attempts to correct seat leakage through-Target Rock high -- temperature, high pressure solenoid operated valve NG-50V-470; Auxiliary feedwater pump turbine governor adjustment; -- i Modification to replace solenoid operated valves controlling the --
containment air recirculation fan damper position; Modifications to service water pump sizes; i -- Modifications to service water flow instruments: associated with- -- supply to the containment air recirculation fan coolers; Repair of the "A" station battery charger; -- Investigation and repair to latching relays 27Y2/1-8 ar.d -- 27Y2/1-9; Investigation into the cause for-the "A" emergency diesel -- generator breaker failing to close during a manual loading test and the recalibration of the synchronizing check relay;
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. Modificatiotts to pin the operating lever of Westinghouse type -- HFA molded case circuit breakers in the close posi ion to- - - t preverit inadvertent opening of that breaker type;- Modifications to remove auxiliary boiler heating steam piping -- from the "A" electrical switchgear area-_and the control room ventilatinn equipment room by cutting and capping the lines;:and = ' Transformer turns ratio tap c ages of the 115ky to 4160 volt -- and 4160 to 480 volt station service transformers.- No unacceptable conditions were identified.
4.2 Sr W 11ance Observation ine. inspectors witnessed selected surveillance tests to-determine whether: properly approved prccedures were in use; plant' technical specification frequency and action statement requirements'were satisfied; necessary equipment-tagging was performed; test
instrumentation was in calibration and properly used; testing was-performcJ by qualified personnel;-and, test results satisfied accep-tance criteria or were properly dispositioned Portions ~of'activi- ' ties associated with the following procedures were-reviewed: + > , ST 11.7-12, "3989 Refueling Outage Plant Integrated Test" -- SUR 5.7-148, " Inservice Testing of A,_B, C and D Service Water -- Pumps Surveillance" SUR 5.2-50, " Reactor Trip Checkout" -- ST 11.7-13, 'B' Switchgear Room' Compliance Test" -- SUR 5.1-4A, "F.mergency Core Coo _ ling Systems Leak Test (Mode 4)"- -- 3_ SUR 5.1A-15EA, " Electric Fire Pump Operability Run -- - SUR 5.7-31, " Inservice Testing of Boric Acid and RWST Check -- Valves, BA CV-320, 372, and 387" SUR 5.7-144, " Inservice Testing of A & B Charging Pumpt.
-- 4: Surveillance" SUR 5.1-126, " Locked Valve Checklist" -- SUR 5.1-155A, " Electric Fire Dump (P-4-1A) Monthly Test" -- SUR 5.1-159, " Boron Injection Path Valve Lineup and Metering- -- Pump Test" SUR 5.1-4, " Emergency Core Cooling Systems Test" -- l .
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. , 10- , + , SUR 5.7-1474, " Inservice Inspection of A&B Residual' Heat Removal- -- Pumps Quarterly Surveillance Test"- .PMP 9.5-116, " Auxiliary Feedwater Pump Turbines Overspeed Trip -- Test" SUR 5.1-14, " Auxiliary Feedwater Pump Flow Capacity Test" i -- ! SUR 5.3-39, " Control-Rod Drop Timing Tests" l -- SUR 5.2-2, " Rod Position Instrumentation Calibration" -- SUR 5.7-108c " Containment Integrated Leak Rate Test" ) -- No unacceptable conditions were identified.
4.2.1.P_lant Integrated Electrical Tests-t Extensive tests were conduc.ted to provide final acceptance for l - i modifications made to plant * electrical distribution systems.
, ~ Several outstanding issues were addressed'by these modifica- ' , tions which included compliance with 10 CFR 50, Appendix-R and the resolution of previously identified single failure problems.
The tests were conducted by Special Test Proceaure (ST) 11.7-13, 'B' Switchgear Room Compliance Test", and ST 11.7-12, "1989 Refueling Outage Plant Integrated Test."
, s - The purpose of the first test, ST 11.7-13, was to verify the operation of equipment from the local instrument panel located in the "B" electrical switchgear area, This tculpment would j be used to place the plant in the Hot Shutdown Operational Mode and to maintain those conditions in the event of a fire occurring in the control room.
The results of this test were
to be considered in conjunction with another test which had been conducted during the previous inspection period. During
that test, ST 11.7-15, all incoming power was interrupted to l prove the independence of the "B" safeguards electrical ! division (Reference NRC Inspection Report 50-213/90-08,
Section 4.2.1).
, In the performance of ST 11.7-13 control room instruments were deenergized and operation of corresponding instruments on the j , local instrument panel was verified. Additionally, pumps and , remote operated valves which supported the operation of the "C" component cooling water pump, the charging system metering .. pump and the "A" residual heat removal pump were operated. 'A ' second part of this procedure verified that a loss of equipment in the "B" electrical switchgear area only af fected = instruments powered from the "B" 120 volt d.c. bus.
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', < . The second test, ST 11.7-12, was conducted in six parts.
The= first two parts sequentially tested the automatic actuation of first the "A" then the."B" safeguards division.
This included both the safety injection actuation and the containment isola-
tion systems.
The tests were. conducted after disabling the , automatic start function of the diesel generator in the opposive ' safeguards division along with its 4160 and 480 volt a.c. and = 120 volt d.'c. electrical busses.
l . 'The'second two parts of ST 11.7-12 again sequentially tested; the "A" and "B" safeguards divisions includ,ng a partial loss
of off site power to exercise the diesel generator load sequencers.
The fifth part of'ST 11.7-12 initiated a complete
oss of off site power to allow emergency diesel start. 'The
- inal test combined a safeguards actuation with a loss of off site power.
The' inspectors observed.the conduct of these tests, indepen-dently verified equipment performance and followed the e licensee's. tracking of test exceptions. _There were no unac-ceptable conditions identified.
4.2.2 Auxiliary Feedwater Pump Flow Capacity Test Surveillance test SUR 5.1-14, " Auxiliary Feedwater Pump Flow Capacity Test", demonstrated the ability of theLpumps to meet . the performance test required by Technical-Specifications (TS) Surveillance 4.7.1.2,2.a.
Each of the two_ pumps-were to attain rated flow of 450 gpm at 1050_psig pump discharge pressure.
Several problems were experienced-by;the licensee before successfully completing the test.
A TS restriction which effectively prohibited plant heatup above 350 degrees F as the test had not been successfully completed-within the eighteen month period required'to, demonstrate-pump operability. The-turbine driven pump requires steam pressure.in-excess of 600 psig to reach full flow.
The test was to be per-formed with plant temperature near normal operating temperature.
As discussed in Section 2.3.3 of'this report, the= licensee requested and the NRC issued a Temporary Waiver of Compliance i permitting entry into Operational Mode 3 for demonstration of auxiliary feedwater pump operability required by TS
Surveillance Requirement 4.7.1.2.2.
The licensee experienced some difficulty in successfully_ i performing SUR 5.1 14 when first performed with the "A" and ! "B auxiliary feedwater (AFW) pumps on July 29 and 30, _
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, -12 i .. ! I respectively. The problem was found to be with the turbine i governor settings which were adjutted during preventive l - maintenance testing of the turbi.ie sverspeed trips on July 27 and 28.
t The governors were adjusted to limit turbine speed to approxi- ! mately 4450 rpm while. setting the overspeed trip to.5200 rpm.
! This was conducted with th'e pump disconnected from the turbine- . to allow reaching the overspeed trip point.
The pumps were ' then re-coupled and functional and flow capacity tests per- , formed, a The turbine speed was found-to be limited by the governor when ! full flow tests were conducted.
This was apparently due to > the large difference in governor valve position bstween no i load and full load conditions.
The difference in speed was a
result of the error required by the single' element mechanical
proportional control system for-its operation.
' Following analysis of the problem, th' e licensee authorized resetting of the governors under full flow to a maximum speed' of 4590 rpm. The turbine vendor suggested this limit based on turbine ~ lubrication concerns.
The pump vendor only required . shaft power limits.- Final-settings resulted in "A" AFW pump performance of 474 gpm , at 1063 psig pump discharge pressure.
This was attained at
4525 rpm, 625 psig turbine steam chest pressure and 8 psig pump suction pressure.
The "B" AFW pump produced 487 gpm, at i 1050 psig, 4435 rpm, 600 psig steam pressure and 7 psig pump
suction pressure.
The inspector reviewed the licensee's actions and' observed the final capacity tests of each pump.
There were no unacceptable , consitions identified, j 4.2.3 Containment Integrated Leak Rate Test
Ouring this inspection period, the licensee conducted the
containment integrated leak rate test (ILRT) 'as required by 10-CFR 50, Appendix J.
Several lessons lesrned from the . 1987/1988 refueling outage ILRT were incorporated into this ' test. The previous test encountered diurnal effects which inhibited temprature stabilization ' prior.to the. actual--ILRT.
To prevent similar test-delays, service water cooling to the l containment air recirculation.(CAR) system was isolated, the , CAR fans were not operated, and dditional e xling water was supplied to the air compressors r a more centrolled , containment air temperature during pressurization.
In previous. tests, the leak check of all penetrations prior to . t - t
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I i the 24' hour ILRT was optional. This leak check was made mandatory to provide early identification of potential leaks i and expedite leak isolation should it become necessary during > the test.
Incorporation.of.t.hese changes succes5 fully-
supported a smooth temperature stabilization and quick __ identification and isolation of a leaking penetration valve.
' 4.2.3.1' Test Procedures ! ' The procedures-for conduct of the ILRT have been rewritten - for this outage. The ILRT procedure was subdivided into i the following procedures which cover. individual portions of-l the test preparations and execution: 'y ENG l.7-86, " Pre-ILRT Valve Lineup" -- . ENG 1.7-91 " Installation of Temporary ILRT -- Instrumentation" , ENG 1.7-92, "f.e.-ILRT and Post-ILRT Containment- -- . Readiness and Visual Inspections" ! . , ENG 1.7-93, "ILRT Leak Check During Test" -J -- .! ' ENG 1.7-97, CPressurization Equipment Setup" --
SVR 5.7-108, " Containment Integrated Leak Rate Test" -- The inspector reviewad portions of these procedures to { verify compliance w) J 10 CFR 50, Appendix J.
In.
! particular, valve lineups _ were reviewed to verify that systems were properly aligned to expose containment - ' isolation valves to the containment atmosphere and provide leakage detection capabilities.
A major. improvement to the procedures is.the incorporation of' detailed penetration-drawings into the body of procedures ENG 1.7-86 and.ENG 1.7-93.
The diagrams reflected the required ILRT system-
configuration and were valuable operator aids during - initial system lineup and subsequent _ leak checks, r s 4.2.3.2 Test Conduct >
Date Time-Activity.
. 7/3/90 0501 Commence pressurization of containment.
0548 High containment pressure alarm received at 3.5 psig.
, 0626 Containment _ isolation signal received at 4.5 psig.
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i 0841 Containment prassure is 10 psig.
! l 0845 Containment isolated for one hour ! stabilization. Operations conduct j initial r,enetration walkdown -; . : 1328 Recommence pressurization.
, . 1500 Received fire alarm in containment.
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i '1525 Containment fire detection. system
. declared inoperable, en ry into 'TS 3.3.3.6.b.
- ! 1527 . Operations instructs ILRT personnel to ' monitor containment RTDs hourly to -! satisfy TS 3.3.3.6.b.
' i 1710 RTD No. 20 out of range low, leak rate-l calculation weighting factors reset to ' t - compensate.
7/4/90 0417 41.59 psig. test pressure achieved.
Containment isolated.
!
0730 Commence. temperature stabilization.
! ! 0912 Operators initiate penetration leak ~ checks-per ENG 1.7-93.
' 1139 Temperature stabilized. Commence ILRT.
i i-1336 Identified leak on RH-MOV-31.
, 1417' HS-V-382 closed tocfacilitate testing ' of HS-TV-380 and -381.
j 1625 RH-MOV-31 isolated.
Terminate ILRT.
' Recommence. temperature stabilization, t 2213 Temperature stabilized.- Recommence ILRT.
l 7/5/90-2247 Completed ILRT (24-hour test), 2348 Established 10.37 SCFM superimposed ' ' leak for verification test.
< 7/6/90 0105 Temperature stabilized. Commence ' verification test.. ! l r P - -- ,,, y .._-
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l 0230 Valve packing leak identified in-i . verification test lineup.
' 0300 Leak stopped.
Recommence verification
test.
} 0710 Complete verification test (4 hour test).
0945 Commence containment depressurization.
i 4.2.3.3 Test Observations During containment pressurization a fire alarm annunciated-and locked in for the containment building. Operators determined that containment air temperature did not-i indicate the presence of a. fire and they conservatively declared the entire containment fire detection system out
of service. Technical Specification 3.3.3.6 b. requires , that, with less-than the minimum required fire detection
instruments in service in containment, containment is
either inspected once per eight hours or air temperatures are monitored hourly. ' Entries into containment wereLimpos-sible because pressure was greater than 10 psig. The:in- !
spector verified that operations and ILRT personnel per-
formed this monitoring for the duration of the ILRT.
The , containment temperatures remained uniform throughout tb
test and an inspection following the ILRT identified no . t evidence of fire.
About five hours into the 24 hour' hold portion of the ILRT i it became apparent to test personnel that a leak was present.
Operators were dispatched to observe the penetra-tion locations which were identified as~ potential leakage ' locations during the leak check.ENG.I 7-93.- A large leak i was quickly identified on RH-MOV-31 and the valve was , isolated by a blank flange..The ILRT was terminated and ' temperature stabilization restarted.
Repair of RH-MOV-31 .; occurred following the ILRT.- The local leak rate test l results were accounted for in the as-left containment _ leak-
age,
- i The verification test was similarly interrupted. After
about two hours of the four hour test, a leak was identi-fied from packing of a ventilation sample line valve in the lineup to the verification test equipment. Once the packing was tightened, the verification test was reinitiat-
ed and successfully completed.
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. . The inspector verified penetration lineups and performed
, system leak checks independently and with licensed opera- ! tors prior to and during the ILRT. The' inspector =noted ( that leak check procedure format aided in efficient pene-a tration inspections and quick location of system leaks.
l Test conduct and data collection by the ILRT test personnel ) were observed.
Communications and coordination between ' operations and test personnel and procedure adherence were good.
4.2.3.4 _est Results T The licensee evaluated the test results for the 24 hour ! ILRT period, 10:22 p.m. on July 4, 1990 to 10:47 p.m. on l July 5, 1990.
Using the mass point method of calculat. ion, i the upper confidence limit leak rate was 0.0312 weight per-l sent per day.
The test acceptance criteria based on 0.75 La is 0.135 weight percent per day.
The sup'erimposed leak verification test'was also success-ful. A leak of 10.37 SCFM or 0.1839 weight percent per day
was induced.
The test results were within the SUR 5'.7-108 , e acceptance criteria band as follows: Composite leakage (Lc) = 0.199 weight percent per day -
0.1686 50,199 50.2586.
The ILRT results were acceptable. Although RH-MOV-31 ex- , hibited. excessive leakage necessitating penetration isolation
and test restart, the valve had passed the as-found local leak rate test conducted early in the. refueling' outage (see
Section 4.2.4 of this report).
.4.2.4 Local Leak Rate Testing of the Containment Spray Penetration The containment spray penetration (P-80) is isolated by a motor-f operated valve (RH-MOV-31).
The spray system is supplied by the ! fire water system and remains isolated during normal operation
with a fire header pressure greater than 80 psig.
The configura-tion of P-80 is not conducive to a conventional local leak rate test (LLRT).
Therefore, by letter dated. September 9, 1987 NRC
granted the licensee a permanent exemption from the requirements ' of 10 CFR 50, Aprendix J to permit reverse direction testing of t P-80.- This exemption is based on maintenance of_at least 80 psig.
in the fire system header and exposure of the containment side. of RH-MOV-31 to the containment atmosphere during the integrated '. leak rate test (ILRT).
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. The licensee performs a LLRT on P-80 by SUR 5.7.53, " Inservice ! , and Local Leak Testing of Containment Spray' Valves." This test is a reverse direction water test using leak collection at a ' drain valve to quantify leakage through-RH-MOV-31. An estimated i water to air leakage conversion provides a leakage through the - valve.
On October 26, 1989, the as-found LLRT for RH-MOV-31 ' f ailed with a leakage of 41.7 cc/ minute (7.57 pounds mass / day).
. This leakage does not meet the inservice test acceptance criterion (14 cc/ minute) but is well below the technical specification limit of 650 pounds mass / day. The valve was repaired and suc-cessfully tested with 3.3 cc/ minute (0.55 pounds mass / day) leakage.
During the ILRT (see section 4.2.3 of this report), RH-MOV-31 was , exposed to the containment atmosphere as required and exhibited.
' excessive leakage.
P-80 was isolated for the ILRT.
j Following the ILRT, an as-found LLRT was. performed.
The valve , exhibited 105.3 cc/ minute leakage.
The valvo was disassembled
and an accumulation of silt and mud was found on the seat. After . cleaning and reassembly an as-left LLRT was required as a retest l , but an air leakage test in the correct direction was necessary j because P-80 was isolated for the ILRT.
A method for air leakage testing P-80 was developed which required ! , that a system check valve inside containment be blocked closed ' to permit air pressurization of RH-MOV-31.
SUR 5.7-53 was re- ' !. vised and a pressure decay air-leakage test was performed.
The ' valve exhibited 0.14 psi / minute leakage which satisfies the ! acceptance criteria of less than 0.158 psi / minute.
The inspector reviewed the test' methods and results and discussed ' the testing and exemption with inservice test personnel.
Because , a viable air test method has been developed, the licensee has ccmmitted to continue performance of this test for the LLRT and to formally cancel the exemption for LLRT of;P-80.
' . 5.
Security
' During routine. inspection tours, the inspectors observed implementation of i portions of the security plan.- Areas observed included access point search l equipment operation, condition of-physical barriers, site access control, , i security force staffing,.and response to system alarms and degraded condi-
tions. These areas'of program implementation were determined to be adequate.
, l 6.
Engineering and Technical Support
The inspectors reviewed selected engineering activities.
Particular attention was given to safety evaluations, plant operations review commit-tee approval of modifications, procedural controls, post-modification testing, procedures, operator training, and UFSAR and drawing revisions.
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j . . ! 6.1 Emergency Diesel. Generator Load Analysis , During an engineering review, the licensee discovered a condition in f which the "B" emergency diesel generator (EDG) load may exceed the .i maximum load to which the machine is surveillance tested. Technical i Specification surveillance 4.8.1.1.2.5 requires that periodic testing ' be made with a generator load between 2750kw and 2850kw.
! During a review of loading combinations specified in the emergency operating procedures, the licensee found a limiting case in which the
diesel generator load exceeded 2850kw.- For the condition of a loss i of coolant accident with the loss of off site power and the-failure I of the the "A" EDG. the combination of automatically sequenced and l manually started loads powered by the "B" EDG was calculated to be 2915.35kw. This condition was found_to potentially exist for up to ' - 12 minutes. The problem only concerned _the "B" EDG because of new ! additional loads associated with the recently completed "B" , electrical switchgear area.
, ! The G^neral Motors Electro-Motiv'e Division. stationary power plants ! , are rated at: . , 2600kw Continuous ! 2850kw 2000 Hours per year- ! 2950kw 7 Days
3050kw 30 Minutes \\ The-licensee conducted a test in_which the machine was loaded to . ) 2950kw with 1650kvars reactive power for 15 minutes. Generator load was then decreased to 2800kw for two hours.
This, test was conducted i on July 13, 1990 under work order CY 90 07136 and Temporary Procedure Change No. 90-663 to surveillance' procedure SUR 5.1-17B, " Emergency l Diesel Generator EG-2B Manual Starting and Loading Test."
The inspector reviewed the test data along with the following diesel i generator load profile studies: , Calculation No. PA-78-741-01-GE, Revision 2, dated June 20, 1989; -- Operability Evaluation and Reportability Evaluation-No. 89-44 ! -- (CY); i
Memos on diesel generator load studies Serial No. ODM 89-528, -- dated December. 8,1989 and No. GEE-90-237, dated July 13, , ! 1990; and , Letter from GM-EMD on diesel generator load ratings dated -- January 7, 1981.
No.;nacceptable conditions were identified.
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l ., ) 6.2 Installation of New Containment Isolation Valve , During this refueling outage, several unsuccessful attempts were made at renairing and satisfactorily leak rate testing-valve NG-50V-470, which is the outboard containment isolation valve for the nitrogen.
j supp*y to the pressurizer relief tank (PRT), Since an identical
rep 1icement valve is not readily available, the licensee elected to i install a new containment isolation valve between NG-50V-470 and the containment wall. Manual ball valve NG-V-473 was installed by Plant . Design Change Record Evaluation (PDCE) 90-140, " Add New Manual
Containment Isolation in PRT Nitrogen Gas Line (P-20)" during this
inspection period.. This valve will be a locked clot,ed, containment isolation valve and has been added to SUR 5.1-126 " Locked Valve Checklist" and, following the necessary technical specification . change, will be controlled similarly to other manual containment ' isolation valves.
The. inspector reviewed the PDCE package, implementation, and post I modification testing.
The appro.priate engineering design reviews and > safety evaluations have.been performed and this change does not , constitute an unreviewed safety question. The inspector. verified t that the appropriate procedure c'..nges were implemented and the necessary control room drawing changes were made. The local leak rate test was successfully performed for this containment penetration l prior to establishing containment integrity.
No deficiencies were-identified with this modification.
6.3 Electrical Modifications l . ' 6.3.1 Background In a letter dated August 25, 1986, from H. R. Denton to J. F.
Opeka, " Fire Protection Exemption - Haddam Neck Plant," the i NRC Staff granted Connecticut Yankee Atomic Power Company
(CYAPCO) an exemption from the schedular requirements of Section 50.48 and Appendix R to 10 CFR Part 50 for the Haddam Neck Plant.
This exemption pertained to the construction of.a , new switchgear building providing the separation of redundant electrical divisions..This is required to achieve shutdown and to maintain the facility in a safe shutdown condition - l during a fire related e,ent.
A separate, seismic category I building was constructed to ' house selected safety train B and channels C and 0 electrical ' equipment.
The new switchgear room is designated as the "B"
switchgear room.
Modifications have also been made in the original switchgear room now redesignated as switchgear room
"A".
Provisions were also made for isolation of power and control sources in the event of a fire in various plant areas.
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The licensee performs a LLRT on.P-80 by SUR 5.7.53, " Inservice , and Local Leak Testing of Containment Spray Valves.". This test is a reverse direction water' test using leak collection at a drain valve to quantify leakage through RH-MOV-31. An estimated , water to air leakage conversion provides a leakage through the i valve. On October 26, 1989, the as-found LLRT for RH-MOV-31 ! failed with a leakage of 41.7 cc/ minute (7.57 pounds mass / day).
I This leakage does not meet the inservice test acceptance criterion ! (14 cc/ minute) but is well below the technical specification limit of 650-pounds mass / day.. The valve was. repaired and suc- + cessfully tested with 3.3 cc/ minute (0.55 pounds mass / day) leakage.. During the ILRT (see section 4.2.3 of this report), RH-MOV-31 was exposed to the containment atmosphere as required and exhibited '! excessive leakage.
P-80 was isolated for the ILRT.. ! Following the ILRT, an as-found LLRT was performed.
The valve exhibited 105.3 cc/ minute leakage. The valve was disassembled and an accumulation of silt and mud was found on the seat. After cleaning and reassembly an as-left LLRT was requirtd as a, retest
, but an air leakage test in the correct-direction was necessary j because P-80 was isolated for the ILRT.
~ A method for air leakage testing P-80 was ' developed which required I that a system check valve inside coi air. ment be blocked closed to permit air pressurization of RH-MOV-31.
SUR 5.7-53 was re- , vised and a pressure decay air-leakage test was performed.- The valve exhibited 0.14 psi / minute leakage which satisfies the acceptance criteria of less than 0.158 psi / minute, , ! The inspector reviewed the test methods and results and discussed the testing and exemption with inservice. test personnel.
Because a viable air test method has been developed, the licensee has committed to continue performance of this test for the LLRT and,
to formally cancel the exemption for LLRT of P-80.
' 5.
Security During routine inspection tours, the inspectors observed implementation of-
portions of the security plan. Areas observed incluoed access point. search equipment operation, condition of physical barriers, site access control, .) security force staffing, and response to system alarms and-degraded condi-
tions.
These areas of program implementation were determined to be adoquate.
! 6.
Engineering and Technical Support t The inspectors reviewed selected engineering activities.
Particular attention was given to safety evaluations, plant ope. rations review commit-tee approval of modifications, procedural controls, post-modification testing, procedures, operator training, and UFSAR and drawing revisions.
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l , . . t I i 6.1 Emergency Diesel. Generator Load Analysis During an engineering review, the licensee discovered a condition in ' which the "B" emergency diesel generator (EDG) load may exceed the i maximum load to which the machine is surveillance tested. Technical ' Specification surveillance 4.8.1.1.2.5 requires that periodic testing be made with a generator load between 2750kw and 2850kw.
i t During a review of loading combinations specified in the emergency i operating procedures, the licensee-found a limiting case in which the ! diesel generator load exceeded 2850kw.- For the condition of a loss ! of coolant ' accident with the loss,of off' site power-and the failure , of the the "A" EDG ; the' combination' of automatically sequenced and - i manually started Iceds powered by the "B" EDG was calculated to be i - 2915.35kw.
This condition was found to potentially exist for up to ! 12 minutes.
The. problem only concerned the "B" EDG because of: new ! additional ic Ms associated with the recently completed "B" electrical suitchgear area.
' , , , The General Motors Electro-Motive Division stationary power' plants
are rated at: , 2600kw Continuous l 2850kw 2000 Hours per year ! ' 2950kw 7 Days
3050kw 30 Minutes The licensee conducted a test in which the machine was loaded to 2950kw with 1650kvars reactive power for 15 minutes.
Generator load - was then decreased to 2800kw for-two hours.
This test was conducted
on July 13, 1990 under work order CY 90 07136 and Temporary Procedure ! Change No. 90-663 to surveillance-procedure SUR 5.1-178, " Emergency
Diesel Generator EG-2B Manual Starting and Loading Test."
The inspector reviewed the~ test data along with the following diesel generator load profile studies: i Calculation No. PA-78-741-01-GE, Revision 2, dated June 20, 1989; -- Operability Evaluation and Reportability. Evaluation No. 89-44 -- (CY); Memos on diesel generator load studies Serial No. ODM 89-528,
-- dated December 8,1989 and No. GEE-90-237, dated July 13,
1990; and I Letter from GM-EMD on diesel generator load ratings dated -- January' 7,1981.
No ur. acceptable conditions were identified.
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l , i l 6.2 Installation of New Containment Isolation Valve During this refueling outage, several unsuccessful attempts were made ! at repairing and satisfactorily leak rate testing valve NG-SOV-470, ! which is the outboard containment isolation valve for the nitrogen . supply to the pressurizer relief tank (PRT).
Since an identical > replacement valve is not readily available, the licensee elected to ~ install a new containment isolation valve between NG-SOV.470 and the
containment wall.- Manual ball valve NG-V-473 was installed by Plant
Design Change Record Evaluation (PDCE) 90-140, " Add New Manual
i Containment Isolation in PRT Nitrogen Gas Line (P-20)" during this l inspection period.
This valve'will be a locked closed,' containment isolation valve and has been added to SUR 5.1-126, " Locked Valve ' Checklist" and, following the necessary technical specification , change, will be controlled similarly to other manual containment-isolation valves.
- ! The inspector reviewed the PDCE package, implementation, and post modification testing.
The appropriate engineering design reviews and - safety evaluations have been performed and this change does not constitute an unreviewed safety question.
TheLinspector verified ' l I that the appropriate procedure changes were. implemented and the ' necessary control roca drawing changes were made.
The local leak l rate test was successfully performed-for this containment penetration prior to establishing containment integrity.
l No deficiencies were identified with this modification.
6.3 Electrical Modifications l 6.3.1 Backaround In a letter dated August 25, 1986, from H. R. Denton to J. F.
Opeka, " Fire Protection Exemption - Haddam Neck Plant," the NRC Staff granted Connecticut Yankee Atomic Power Company (CYAPCO) an exemption from the schedular requirements of ' ., l Section 50.48 and Appendix R to 10 CFR Part 50 for the Haddam '- Neck Plant.
This exemption pertained to the construction of a-new switchgear building providing the separation of' redundant electrical. divisions. This is required to achieve shutdown - i ! and to maintain the facility in a-safe shutdown condition L during a fire related event.
' A separate, seismic. category I building was constructed to house selected safety train B and channels C and D electrical.
equipment.
The new switchgear room is designated as the "B" l I switchgear room. Modifications have'also been made in the original switchgear room now redesignated as switchgear room "A".
Provisions were also n..de for isolation of power and control-sources in the event of a fire in various plant areas.
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.. - 20 I The NRC staff submitted a " Safety Evaluation Report (SER) Relating to Electrical System Changes for Fire Protection, , Connecticut Yankee Atomic Power Company, Haddam Neck Plant" to , the licensee in a letter dated January 22, 1990.
In a letter-of June 'll,1990,'the licensee submitted to the staff its " Comments on Safety Evaluation Report." These clarifications and revisions were necessary to reflect' design, modifications.
that occurred after the conceptual design'information was , submitted to the staff.
l 6.3.2 Purpose
i The licensee has'made extensive modifications to the.electri- ' cal systems, in compliance.with the fire protection require- ! ments of 10 CFR Part 50 Appendix R,. to assure a safe shutdown ! of the unit in the event of a fire at the facility, j This inspect 1'n was conducted to ascertain whether the
licensee electrical systems modifications were designed, and.
' components purchased, installed, and tcsted in accordance.with
NRC regulations and the licensee commitments.
> , . 6.3.3 S_c op_e The inspector reviewed documents, inspected installed electri-cal equipment, and witnessed special electrical tests to evaluate the licensee activities in the following areas: -- Design change process ' -- Drawing control .. - - Updated Final Safety Analysis Report (UFSAR) review . -- Eng Neering support { -- Design changes - -- Problem reporting and corrective action
-- Security and tornado protection ' ! -- Mechanical and electrical system-interactions -- Electrical separation
-- Electromagnetic and radio interference with j instrumentation systems -- Station batteries surveillance and' testing , -- Special electrical tests-i 6.3.4 Findings and Conclusions
6,3.4.1 Design Change process A plant design changa is a modification _to a plant struc-- i ~ ture, system, or component that affects the existing form
(shape), fit, function, or material of that structure, E system, or component, , T f --
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. i The des,ign change process is controlled by quality assur-ance procedures. The quality assurance procedures are the administrative control procedures (ACPs) that provide a , detailed method by which plant design change records (PDCRs) i are prepared, reviewed, and dispositioned. This process ensures that safety and the basis for the safety analysis are not compromised by the plant design change.
The ACPs that the inspector reviewed.for compliance with 10 CFR Part 50 Appendix B requirements, are listed in Appendix _ A.
The PDCRs reviewed for compliance with the ACPs and NRC requirements and licensee commitments are also listed in , Appendix A.
The inspector concluded that the licensee design control process and the design changes reviewed are in compliance - with the NRC requirements and the licensee's quality assur-ance administration procedures, i 6.3.4.2 Drawing Control . Unrevised drawings having changes are logged with design ' change notices (DCNs).
The DCN identifies all changes.
Original drawings and original DCNs are maintained in the corporate engineering office.
Controlled copies of these drawings and DCNs are provided to the site.
No criterion exists requiring that a drawing be revised after a certain number of DCNs are logged.
Drawing of critical systems that have been modified must be revised thirty days after system turnover.
Drawings of non-critical ~ systems that have been modified must be' revised ninety days after system turnover. Marked-up critical system drawings are available in the entrol room prior to the drawings being revised to show all changes that resulted from the modifications.
The inspector concluded that the drawing control is adequate to preclude improper system changes or operational problems.
6.3.4.3 Updated Final Safety Analysis Report (UFSAR) Review The inspector reviewed the UFSAR Section 8.3.1.1.2 "480V i System Description" and noted the following statement: "The circuit breaker components in all motor control' centers (MCCs), except MCC-5 and 6, have interrupt ratings of not lessthan15,000 amps [ amperes],whichisadequateforthe.
maximum fault duties." This statement is incorrect since the original breakers were Westinghouse type HFA rated as 25,000 amps and the available fault currents at the MCCs exceeded 15,000 amps.
An additional statement: " Circuit breaker components in MCC-5 and 6 whose supply cable-r l l ,
. .g
. connections from'the switchgear are short, have interrupting ratings of not less than 30,000 amps." This statement is also incorrect and the rated value should be 25,000 amps.
The UFSAR states that all 480 volt system motors are rated ' to operate at 440 volts + or - 10 percent.
The motor data sheets for motor-operated valves (MOVs) 901 and 902 reference that these motors are rated at 460 volts;'therefore, the minimum voltage is 414 volts.
However, the 440 volt motor minimum voltage is 400 volts.
If the degraded voltage, alarm.. automatic protection, or procedures are based on the parameters of 400 volts then the 460 volt motors will operate below their minimum limit. This operating condition may cause motor damage.
The UFSAR states that following a generator. lockout relay actuation, the reactor coolant pumps (RCPs) will transfer.
to the auxiliary bus provided that there is " full voltage" available at the auxiliary bus.
In a memo from W. H. Becker to G. H. Tylinski dated July 2,1990, this value was stated to be 80 percent of the RCP motor rated voltage.
The above UFSAR discrepancies were discussed with the licen-see.
The inspectors _ consider these UFSAR errors to be of - minor significance and have minimal impact on safe plant operations.
6.3,4.4 Engineering _ Support The inspector reviewed the PDCRs and. supporting engineering documents and held discussions concerni_ng'the modifications with engineering personnel both at the site and at North-east Utilities Headquarters.
The inspector concluded that the engineering support'is ! generally adequate to support the modifications; however, ' there appears to be a weakness in the initial setpoints for the new 480 volt Westinghouse Type HMCP motor circuit pro-tectors breakers used in motor-operated valve electrical' protection.
This initial misapplication of trip setpoint is discussed in detail 6.3.4.6 and in Appendix C of this-report.
6.3.4.5 Design Changes j . There were no changes to the 4160V safety-related buses 8 and 9 that are supplied normal station service power and < emergency power from the standby emergency diesel genera-tors (EDGs). The bus 8 EDG 2A and bus 9 EDG 2B are located ! , .
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I . in separate Category I structures. A new feed was supplied
from bus 9 to the new load center transformer 4911 discussed below.
The auxiliary transformers, 4160V/480V (numbers 484, 485, 497, and 498), were originally purchased with insulating ' oil that also contained polychlorinated biphenyls (PCB).
These ' transformers were located in the original switchgear , room now designated "A.". They have been replaced by dry . type transformers to reduce potential fire load in the { switchgear room "A" and economic-concerns about PCB con-tamination in the event of a fire in_this switchgear room.
" The new electrical = equipment was' installed in.the new switchgear room designated as room "B." The. details of this new equipment, load lists, and instrument and control trans-t fer are contained in Appendix B.
The equipment che.nges in .> the original switchgear room "A" are also detailed in j Appendix B.
, .^ The inspector concluded that the design changes-reviewed
achieved the separation of the systems and components ! selected; however', the systems and components selected to achieve safe shutdown in the event of a fire are not within.
the scope of this inspection, t 6.3.4.6 Problem Reporting and Corrective Action ' -- 480V Load Center Breakers Deficiencies The NRC was informed by the licensee of a 10 CFR Part 21 I report that the vendor's (ASEA Brown-Boveri Inc.)'480V Load " Center Circuit Breakers, Model Nos. K-3000 and K-1600, con-tained defects.
These breakers are used in Bus 11 of the
modification. An additional def.ct was discovered after- , this report was made.
Information concerning this latter ' defect was provided by the licensee in a letter to the NRC,
This defect was only discovered af ter extensive breaker testing.
The vender responded to the 10 CFR Part 21 report in'a letter to the NRC.
The specific problems, including the problem ' identified in the licensee letter of June 5, 1990, and cor-rective action are detailed in Appendix C.
, The arc chutes material appears to be brittle and was damaged during shipping.
Additionally, it appears to be' susceptible to damage during breaker operations.
The vendor has in-structed the licensee to continue tc, use the existing arc , chutes while the vendor attempts to i.orrect this problem.
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. . The inspector concluded that the licensee corrective actions for the above problems are adequate; however, the vendor's-root cause and corrective action appears to be inadequate.
480V AC Motor Control Center (MCC) Molded Case Circuit -- Breakers Misapplication The ifcensee submitted Licensee Event Report 50-213/89-016 concerning installed breakers in the existing MCCs in accordance with the requirements:of 10 CFR'Part 50.73.
A number of breakers,' located in three MCCs..had current interrupting ratings of 14,000 amps (symmetrical), whereas the available fault currents at-the breakers ranged from 19,634 amps to 22,524 amps.
The licensee's corrective action was to. replace the incor-j . rectly rated breakers with breakers that had the proper ratings.
This replacement was controlled by plant design changa record (PDCR) 983.
This replacement also included those breakers without traceable records.= The root cause of this problem and additional details are given in Appendix C.
The inspector concluded that the licensee has. identified the correct root cause of the problem and has provided ade-quate corrective action.
125 Volt _DC Bus Breakers Trip Setpoint Drift -- The licensee identified in plant information report (PIR) 90-102 that some 125 volt a.c. molded case breakers trip responses were not acceptable.
The licensee had elected to replace all the 125 volt d.c. breakers in panels "A" and "BX" because of trip drift, the age of the breakers, and thv unavailability of replacement breakers.
This replace-ment was controlled by PDCR.995.
Details of this replace-ment and the technical evaluation determination of report-ability are detailed in Appendix C.
The inspector concluded that the licensee has used good judgement in replacing the 125 volt d.c. breakers in panels "A" and "BX" and that the licensee was not required to report this problem to the NRC.
125 Volt DC Bus Breakers Load Derating -- The licensee identified in PIR 90-94 that the breakers on bus "B" did not include the load derating determined by the vendor, NUTHERM, through environmental testing.
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, The licensee initiated a reportability evaluation, REF 90-12, and perforne:I an engineering evaluation of actual connected loads verses the derating values. The licensee requested j the vendor to supply breaker load derating that represent the "B" switchgear room environment.. Details of this de-rating'and the licensee engineering evaluation are contained j in Appendix C.
, The inspector concluded that the licensee's corrective action is adequate.
l Type HMCP Motor Circuit Protection Device Inadeouate Trip-l -- letpoint '
In PIR 90-95, the licensee identified that the trip settings' of Type HMCP motor circuit protection devices, used in motor , f control centers (MCCs) for motor-operated valves (MOVs) SI-MOV-901 and 902 cause the breakers to trip. The West-
inghouse-Type breaker HMCP trip setting was specified as 10
times.the motor running current. These breakers tripped during the valve testing.
The trip setpoint for these breakers was changed to 12 times the running current and the valves were tested-with no further breaker trips.
Details of this problem are discussed in Appendix C.
The
inspector concluded that the corrective action should be > justified, by the licensee, since the HMCP type breaker > trip time is one cycle compared to the six cycle trip of < the older breakers.
The HMCP breaker can respond to the-subtransient starting currents and current increases. in MOV ! motors due to voltage up to ten percent of their design l rating, The licensee changed the trip-set' point to 210 ' percent of the motor locked rotor current. Details of this i change are given in Appendix C.
l The-inspector concluded that the latest set point-should permit the motors to perform their-safety function and pro-vide them with adequate electrical protection. This resolves a previously identified unresolved item (90-08-02).
. 6.3.4.7 Security and Tornado protection ' s The inspector's walkdown of the cable tray and conduit system, ! associated with the Appendix R modification, identified
covered. cable trays and conduits leaving a vital building , and exiting a transition box along the "A" diesel generator l enclosure, They then ran vertically outside the vital build- ) ing, then proceeded horizontally over the diesel generator roof, vertically up a wall, and horizontally to the pene-tratic.n of the service building north exterior wall into i ' . i lJ
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j . i .the area above the control room. The inspector discussed , this concern of exposing safety related instrumentation and l control cables to secur;.y and tornado risks.
j The licensee furnished the inspector a memorandum from G.- R. Pitman to_C. J. Gladding, dated September 14, 1989, that . addresses the mentioned risks.
The iicensee concluded that.
with the new Appendix R modification the security, tornado, ' and high wind risks are acceptable because the peripheral i benefits of the Appendix R modification allow the unit to i ' be safely shut down if the discussed cables were damaged accompanied by associated shorts to ground, cable to cable , shorts, and open circuitry.
t The inspector agreed with: licensee conclusions that, even with cable damage, the plant could safely shut down.
Mechanical and Electrical _ System Interaction -- The ins'pector walked down-the following areas to determine , if there were any mechanical systems (i.e. fire protection, j' heating systems, air cooling, etc.) that'could potentially cause failures of safety-related. electrical systems: ! ! \\ Switchgear room "A" -- Switchgear room "B" -- EDG -2A and 4160V bus 8 switchgear room -- EDG -20 and 4160V bus 9 switchgear room -- The following potential. interactions were identified during the walkdown:- The maintenence lifting trolley located above each EDG -- did not appear to be secure enough to-prevent damage to the EDG starting air piping duringLa seismic event.
- The ventilation system located above and to the rear -- of the "A" battery is supported by sheet metal straps which may not provide adequate support during a seismic event. This lack of support may cause battery damage during a seismic event.
During the week cf June 25, 1990,-the licensee had performed an engineering walkdown in the following buildings to iden-tify seismic interaction between safety-related equipment' and transient materials stored within these buildings: Primary Auxiliary Building -- Emergency Diesel Generator Enclosure -- Auxiliary Feed Pump (Terry Turbine) -- _ .
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- i Spent Fuel Building -- Switchgear Rooms -- Control Room-l -- Screen House -- i The above potential interaction identified by the inspector was not in the scope of the walkdown by_the licensee, which
was to' identify transient materials.
' 'i The above potential interactions were discussed with the licensee.
There are no procedures to assure the trolley is-i secured after maintenance activities with the EDGs.
There j is no analysis to assure the adequacy of the ventilation l system support to. prevent damage to the battery.
The licensee secured.the trolleys in the EDG rooms prior to ! the end of-the inspection period.- In July 1989 the licensee identified the' vent duct over the l battery "A" and "B" as a potential seismic 2 over 1 condi-t tion.
A reportability evaluation 89-35(CY) indicated that
this condition was not reportable to the NRC under 10 CFR ! 50.72/73. Presently the potential problem is only appl _ic-able to battery "A" located in switchgear room "A."
j The licensee will address this problem when the plant walk-
down is completed for the resolution of Unresolved Safety Issue (USI) A-46, Seismic Qualification of Equipment in J Operating Plants. The inspector confirmed that this issue
is being tracked by the-licensee as-an item needing resolu- -' tion within that USI.
Those items are presently within
Project Assignment 90-28, and work is currently scheduled ' to commence in June 1992.
Electrical Separation [ -- !- The design and construction of the Haddam Neck Plant pre-dates most regulatory requirements-with respect to physical ! separation of electrical cable for redundant safety trains.
) The original design and initial plant modifications were reviewed and accepted by the NRC during the Systematic d Evaluation Program (SEP) conducted ten years ago.- The lic-l ensee has expressed the intent to meet current cable separa-tion criteria for modifications to the existing structures , to the extent practical.
y During this outage, the licensee committed to meet current regulatory cr_iteria with respect to cable separation within ) the new "B" switchgear room.
The NRC staff addressed , ' . s ! -. !
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. . electrical separation-in an SER for the new "B" switchgear - room, sent to the licensee on January 22, 1990.
The SER contains the following statement: " Equipment and cables being added were installed to maintain Division A and Division B electrical and i physical separation. Train separation within a divi- . s' ion was alto maintained to the extent practical, and ' the criteria oo Regulatory Guide 1.75 and IEEE Standard j 384 were adhered to in the new switchgear building.and i ' in other parts of the plant to the extent practical.
Physical separation or. protection of redundant,1cetrical , equipment to meet the criteria of Regulatory Gide 1.75 were not the bases for the existing uesign. -Thus, although the additions may not meet current standards ! inallinstances.throughouttheplant,theydo(so]-in most instances and represent a substantial improvement as compared to the initially licensed facility."
Separation was improved on the 4160 volt system when the present EDGs and busses 8 and 9 were installed in separate l buildings; however, the 480 volt AC and 125 volt-DC system ' components were located in the old switchgear room that is-now designated the "A" room.
This modification provided further separation of the 480 volt AC and 125 volt DC systems.
Provisions were also made to transfer-selected power, control, i and instrumentation within the new switchgear room '!B" to i provide a shutdown to hot standby should a fire occur in the common control room or cable spreading area.
. The inspectors conducted walkdowns of the accessible elec- ' trical cable raceways for safety-related equipment.
No deficiencies were identified within the "B" switchgear room.
' installed cable was found to meet or exceed the requirements of'10 CFR 50, Appendix R and Regalatory Guide 1.75.
In ! general, recent modifications involving new cable tray runs ' met the applicable separation criteria.
The inspector iden-tified two potential examples of inadequate cable separation in the cable spreading area and one in the "A" switchgear i room.
These examples are in areas where the licensee is not required to meet the physical separation requirements , of Regulatory Guide 1.75 and were under additional evaluation by the licensee at the close of the inspection.
The results of this-evaluation will be reviewed during future inspections.
Several modification packages were reviewed by the' inspector.
In some instances, current regulatory guidance documents were listed as references giving good evidence of the intent . ' to meet the conservative but not required separation criteria.
Some modification packages, including one that involved - , ( !
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, routing non safety-related cable into areas containing re-dundant safety-related cable, did not refer to current separation guidance indicating that the intent to meet cur-rent regulatory guidance may not be' uniformly applied.
The licensee specification (E-076) for cable routing did not contain guidance for cable separation at Haddam Neck, but en'gineers indicated that the portion of the specifica- , tion applicable to Millstone Unit 3 was'often used.
The ! licensee indicated that an appendix specific to Haddam Neck i was under development, j The inspector concluded that' the modifications have improved the physical and electrical separation of the facility.- ' No notable deficiencies were identified.
! . Electromagnetic and Radio Interference with Instrumentation -- }ystems i During the 1987 refueling outage, the. licensee started the > replacement of the original analog reactor protection system
(RPS) with state of the art digital equipment. The staff submitted a Phase I and 11 safety evaluation report (SER) .; of the RPS upgrade at the Haddam-Neck Plant.. The following concerns were discussed in the SER: - The radio frequency interference (RFI)-typically occurs l -- at frequencies beyond the concern of the analog design but may adversely affect the digital equipment.
Currently no specific surge withstand capability (SWC) -- or electromagnetic interference (EMI) standards or criteria are firmly established for designs' utilizing ' microprocessors at nuclear plants.
In this SER, the staff required,< prior to restart from Phase 11 RPS implementation, a-plan documenting the analysis or testing to demonstrate the electrical environment of the-new equipment is-envelopsd by the vendor's qualification ( testing.
On June 12, 1990, the licensee issued test procedure-ST 11.7-S1 "RPS EMI Environmental Test."
A' draft ST 11.2-3 " Radio Frequency Interference Test," was. issued'on May 31, 1990.
The adequacy of these procedures to demonstrate that the electrical environment of the new equipment is enveloped-by the vendor's qualification testing'will be determined by ' . the NRC Office of Nuclear Reactor Regulation (NRR) staff.
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. Station Batteries Surveillance and Testino -- lhe inspector reviewed the surveillance, test, and mainten- , ance procedures associated with the safety related station ' batteries.
The procedures reviewed are listed in Appendix D.
The "B" battery has been redesignated "A" battery.
The old ! "A" ba'ttery has been relocated and redesignated "C" batt- ! ery.
A new battery has been installed in the new "B" ' ! switchgear room and designated "B" battery.
The_ perform-
ance test indicated that the "A" battery, which was installed ' in 1983, had a capacity of 106 percent when tested on Sep-tember 20, 1989.
"B" battery, which was installed in 1989, had a 108 percent capacity when tested in June 18, 1990.
i The procedures and tests reviewed were in compliance with i industry standards, license conditions and NRC requirements.
. Special Electrical Testino- -- , As the result of extensive electrical modifications made by the licensee to provide independence of redundant safety
systems, special tests were conducted to assure this inde-pendence and all safety-related systems and components func-tioned as required by the technical specifications and the
UFSAR commitments.
The procedures reviewed, tests witnessed, and problems identified are listed in Appendix E.
The inspector concluded that the special tests conducted: by the licensee did assure the independence of redundant _ . safety-related systems and components and that these systems F functioned as required by the technical specifications and ' the UFSAR commitments.
The problems observed during the
test were adequately *esolved by the licensee with one pos-- sible exception, which concerns the unexpected trip of a , valve motor operator circuit breaker.
The details of this potential problem are discussed in Appendix E, and the lic-ensee investigation was ongoing at the end of the inspection period.
7.
Safety Assessment and Quality Verification-7.1 Plant Operations Review Committee and Nuclear Review Board
The inspectors attended several Plant Operations Review Committee- - , (PORC) meetings and a meeting of the Nuclear Review-Board.
Technical specification 6.5 requirements for required member attendance'were verified.
The meeting agendas included procedural changes, proposed , changes to the Technical Specifications, plant design change records, , and minutes from previous meetings.
PORC meetings were characterized d
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In particular, consideration was given to assure clarity and consistency among procedures.
Items for which adequate review time was not avail-able were postponed to allow committee members time for further review and comment.
Dissenting opinions were encouraged and resolved to the satisfaction of the committee prior to approval.
The inspectors ob-served that PORC adequately monitors and evaluates plant performance and conducts a thorough self-assessment of plant activities and programs.
The PORC conducted reviews of plant readiness prior to commencing the reactor coolant system heatup into Operational Mode 4.
Plant manage-ment was assisted in their review through a newly developed admini-strative system to track items relating to equipment readiness.
7.2 Review of Written Reports Periodic and special reports and licensee event reports (LERs) were reviewed for clarity, validity, accuracy of the root catse and safety significance description, and adequacy of corrective action.
The inspectors determined whether further information was required.
The inspectors also verified that the reporting requirements of 10 CFR j , 50.73, Station Administrative and Operating Procedures, and Technical Specific 6 tion 6.9 had been met.
The following reports were reviewed: LER 90-04 Feedwater Regulator Bypass Check Valves Failed Surveillance Test LER 90-05 Spurious Actuation of the Containment Isolation Actuation System , LER 90-06 Failure to Establish Fire Watch Due to Personnel Error LER 90-07 Postulated Heating Steam Pipe Break Could Affect Safety Related Equipment LER 90-08 Design Deficiency Identified with Solenoid Operated Valves located in Charging Pump Suction Vent Piping LER 89-17 Steam Generator Tube Nondestructive Examination Results.
Revision 1 Annual Occupational Radiation Exposure Report, dated July 12, 1990 Decommissioning Fin: -ial Assurance Certification Report, dated July 18, 1990 Monthly Operating Report 90-06, covering the period June 1, 1990 to June 30, 1990 , No unacceptable conditions were identified.
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, i ! 7.3 Follow-up of Previous Inspection Findings ) i . Licensee actions taken in response to open items and findings from { previous inspections were reviewed.
The inspectors determined if corrective actions were appropriate and thorough and whether previ- ' ous concerns were resolved.
Items were closed where the inspector -
determined that corrective actions would prevent recurrence.
Those items for which additional lice'nsee action was warranted remain open. The following items were reviewed.
, 7.3.1 Full Closure of Core Deluge Motor-Operated Valves i (Closed) Unresolved Item 87-22-05:- Licensee to develop a diverse means of assuring full closure of de core deluge
motor-operated valves (SI-MOV-871A & B). This item was ad-
d.essed in NRC Inspection Reports 50-213/87-22 and 88-08.
Previously, these valves were not leak tested due to system configuration although they represent the primary intersystem i LOCA boundary between the_ reactor coolant and low pressure safety injection systems..The inspectors'were concerned that there was no method to assure full valve closure other than.
control board position indicatien.- To satisfy this concern, the licensee has developed and implemented SUR 5.7-164, " Verify Full Closure of SI-MOV-871A & B Prior to Power Operations." This.is a two part procedure'for obtaining a baseline valve operating trace and-leak rate during'a plant shutdown.
The valve operating trace is than retested and compared to the baseline trace to' verify valve full closure prior to plant power operation, lhe trace is a record of limit switch and torque switch energization periods during valve operation.
The data is recorded using a high speed plotter connected to the valve breaker. The inspector verified that the appropriate portions of the test procedure were performed prior to valve disassembly in September 1989 and prior to mode 4 during this inspection period.
SUR 5.7-164 is included on the Inservice Test and Inspection Refueling Worklist.
This test will also be indicated as a post maintenance. test for these valves in ACP 1.2-11.3, " Retests / Functional Verification." The inspector determined , that these actions to assure. valve closure are adequate.
L3.2 Bulletin 79-18. Audibility of-Evacuation Alarms'in High Noise Areas (Closed) Bulletin 79-18: This bulletin concerns potential inaudibility of the station evacuation alarm in high noise areas.
Licensees were required to evaluate the acceptability of installed public address systems.
This bulletin was - previously discussed in NRC Inspection Reports 50-213/86-27 and 89-10.
In response to this bulletin, the licensee
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, , I initiated plant design change requtst (PDCR) No. 881, "Addi-d ens to Plant Paging System Inside Containment" and PDCR 8 0, " Additions to Plant Paging System Outside Containment."
. Thw PDCRs were completed during the 1987 outage. The ' licensee agreed to test the paging system prior to restart from this refueling outage during Modes 5 or 6 when noi.
level will be higher.
< , ST 11.7-1, " Audibility Verification of Plant Paging System Outside Containment", and ST 11.7-40, " Audibility Verification of Plant Paging System Inside Containment", were i performed during the current refueling outage.
The paging system performance was determined to be acceptable.
However, ' several locations were found to be deficient in audibility of the follow-up announcements.
The evacuation and annunciation alarms are clearly audible in all parts of the plant.
In
most locations the deviations could be corrected by adjust- - ment of the volume. Two locations will require.a plant design change.
Currently, the evacuation and annunciation alarms inside containment are tested daily; outside contain-
ment is tested weekly.
In addition, personnel are encouraged - to report paging audibility problems.
As a general guideline
the licensee tries to maintain the audibility level of the-i page system about 10 db above background. While' adjustments.
arc to be made by I&C personnel only, there have been several
instances of unauthorized volume adjustments.
In most cases i volume adjustment on local speakers is rather simple.. The > licensee has corrected those deviations which do not require-
a design change and committed to correct the two deviations ' which do.
Based on this review, this bulletin-is closed.
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7.3.3 Trip Set Points for Type HMCP Motor Circuit Protection Devices ' (Closed) Unresolved Item 90-08-02: A design change notice (DCN DCY-P-92-90) was issued to PDCR 983 which established a
new trip set point for Type HMCP motor circuit protection , devices of 210 percent of motor locked rotor current.
This
effectively increased the setpoint to between ten to nineteen times motor full load current. There have been no.unaccept-able instances of equipment operation with these new set- ' tings. This unresolved item is closed.
i 8.
Exit Interviews During this inspection, periodic meetings were held with station manage-ment to discuss inspection. observations and findings. At the close.of the inspection period, an exit meeting was held to summarize the-conclu-sions of the inspection.
No written material was-given to the licensee ' and no proprietary information related to this inspection was identified.
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., ' '- , , . In addition to'the exi,t meeting for the routine. resident inspection, the ! , following meeting was held for an inspection conducted by a Region I i based inspector.
.. . . Areas.
! Inspection Reporting ' Report No.
Dates Inspector'- Inspected- , 213/90-14 July:31 - A. Lohmeier-Analysis of reactor coolant- ! August 3 System component.thermalfusage ,1 , - factors ~ .! '; ! I ~_
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, e , e l < , ! APPENDIX A' ' I i DOCUMENTS REVIEWED l l The following Administration Control Procedures'(ACP) were reviewed for compliance with 10 CFR Part 50 Appendix B requirements..
' ! ACP 1.2-2,26, " Implementation'of 10 CFR 21: Reporting.of Defects'and -- Noncompliance'(NEO 2.01)", Rev.1 j ACP 1.2-3.1, " Nuclear Engineering and Operations Procedure (NEO) -- 3.03-Preparation Review, and Disposition of Plant Design Change.
Requests (PRCRs)", Rev. 20 l ACP 1,2-3.2, " Administration of PDCR Turnover, Preoperation- -- Testing, and Release for Operation", Rev. 6 ACP 1.2-3.3, "Setpoint Change Requests", Rev 4 j -- ACP 1,2-3.4, "NEO 5.04-Engineering Specifications", Rev. P.
-- ACP 1.2-3.6, " Nuclear Operation Department (NOD) 3.05 PDCR -- Evaluation" Rev. 3 ACP 1.2-3.8, " Electrical Wiring Verification Functional Testing and- -- i Scheme Verification", Rev. 0 ACP 1.2-6.9. "NEO 3.12 Safety Evaluation", Rev. 5 -- ' ACP 1.2-6.16, " Operations Critical Drawing Handling, Updcting.
-- Identification, and Distribution", Rev. O.
ACP 1.2-6.17 "NEO 4.03 Change and Update' to Final Safety Anslysis -- - Reports for Operating Nuclear Power Plants", Rev. 0 ACP 1.2-6.18. "NEO 4.04 Review and Approval of Proposed Changes ! -- to Selected License Requirements," Rev 0 ACP 1.2-6.19 " Drawing Changes and New Drawing Submitt'als", Rev. O ! -- ACP 1.2-2.26, " Implementation of.10 CFT 21: Reporting.of Defects and- -- Noncompliance (NEO 2.01)", Rev.1 ACP 1.2-2,30, " Identification and Implementation of NRC Reporting .; -- Requirements-(NE0 2.25)", Rev. 0 . The fo11 wing PDCRs were reviewed for compliance with
" the ACPs and NRC requirements and licensee commitments:- '
PDCR W 3, "DC System Relocation for Appendix R", Re'v. 0 -- .-
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'I .PDCR 906, "New Equipment - Old Switchgear Room -'MCC 13-4", Rev.:0 l --
PDCR 907, "MOVs for ECCS Small Break LOCA",-Rev. O ! -- ! PDCR.909, " Appendix R Instrumentation", Rev.LO -- , , . PDCR 910. " Appendix Switchgear. Modifications", Rev. 0.and Addendum ! -- No. I' t . PDCR 931, "CYJ-HPSI' Pump Mihiflow Modifications", Rev. 0 [ --
- p PDCR 983, "480 Volt AC Molded Case-Circuit BreakerfReplacement",
! -- Rev. 0
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~ PDCR 995, "125 Volt DC. Distribution Switchboard Panels "A" and "BX" -- Circuit Breaker Replacement", Rev.-0 The inspector concluded that the licensee design' control! process and the.
- f design changes reviewed are in compliance'with the NRC requirements.and i
, the licensee's quality assurance administration procedures, , ' i.
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. , -. . 9-r APPENDIX B DESIGN CHANGES - DETAILED EQUIPMENT 1.IST AND CIRCUITS ' . Th. turlowing new electrical equipment was installed in the new switchgear ' room designated as room "B," 480V load center bus.11 and dry type-transformer 4911, 4160V/480V, -- 1500/2000 kva, AA/FA, which is supplied power form 4160V bus 9 and alternate power to bus 11 from 480V bus 6.which is also associated with 4160V bus 9.
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. The supplies and load associated with bus 11 are as follows: Incoming supply from LC transformer 491'.(3000A) -- ,
Emergency feed to #4 containment air recirculation (CAR). Fan F-17-4BE -- (normal feed is from 480V bus 7) Emergency feed to #3 CAR Fan F-17-3BE (normal feed from.480V' bus' 6) -- Residual Heat Removal (RHR) Pump B P-14-1B (previously: feed from 480V -- bus 6) Metering pump P-14-1A (previously feed from 480V bus 4). -- Component cooling pump (CCP) P-13-1C (previously' feed from 480V. bus 7) --
Service water pump (SWP) P-37-10 (previously feed from 480V bus,7) -- Feed to lightning panel LP-U7-1 -- Feed to motor control center (MCC) 12 -- Feed from 480V bus 6 breaker.11T6 (1600A) -- 480V MCC 12 which is supplied power from 480V load center bus 11. The- -- following are load supplied from'MCC 12: l Battery room 8 duct heater E-150-1A I - l EDG 2A 480V distribution panel EGG-2B ' - Volume control tank to charging pump isolation valve, CH-MOV-257B - (previously MCC 5-1 bus 5-6) , ..-. _
, .,.. w , Appendix B 2' , Refueling Water Storage Tank '(RWST) to chargin valve, CH-MOV-373 (previously MCC 5-1 bus 5-6)g pump isolation - . .- Feed to lightning panel LP-US-1 - "A" high pressure safety inject 4-(HPSI) pump suction from_RWST.
- , valve, SI-MOV-854A _ "A" HPSI pump suction cross tie valve, $1-MOV-901A - , "A" & "B" HPSI pump recirculation'to RWST valve, SI-MOV-903 - Alternate feed:to semi-vital bus B-SVA- - > Battery room B exhaust _ fan F-91-1A - Alternate feed to "C" vital inverter - Alternate feed to "D'? vital in'verter -
"B" battery charger, BC-1B - -"A" Charging pump auxiliary-lube oil cooling fan, F-89-1A - , ry charger BC-1-B, 460V ac80A/135V dc300A, - 'B'? battery, Gould NCX-17,120V de, 60 cells,1200 amperehour capacity at -- 8 hour discharge rate, SC 1.215
"P' ! distributior panel
to 125V de but 2 is , to Inverter C - .ed to Inverter D c'eed ts 4160V switelgear bus 9 Feed to '80V load center bus 11 - Feed to o distribution panel EGG 2B - "C" inverter, 4iOV ac/125V'dc to 120V ac -- "D inverter, 480V ac125V/ de to 120V ac -- Transfer swite.h panel with the following key lock switches: -- Core exit thermocouples L10, N6, N10, N12.
- Component cooling pump, P-13-1C - ! Residual heat removal pump, P-13-1B -
.:' -
Appendix B
, Charging pump suc, tion from the RWST isolation valve, CH-MOV-373 - Service water pump, P-13-D - Metering pump suction valve CH-A0V-278 v Metering pump P-11-1A - Volume cc.r;roi tank to charging pump suction isolation valve, - CH-MOV-257B t LC transformer 4911 low side brealOr- - -' Bus voltage undervoltage trip reset.
Local Instrument Panel with the following -- indication or controls: ,
Core exit-temperature indication, selector switch, positions 1-L10, - .s 2-N6, 3-N10, 4-N12 -
, Hot and cold leg-temperature for loops 3 and 4 - ' (meter range: 50-750 degree F) Steam generator pressure (meter range: 0-1200 psig).
- Steam generator level (meter range: 0-100 percent) - Primary coolant system pressure (meter range: 0-3000 psig)- - Pressurizer pressure (meter range: 1500-2500 psig)- - Pressurizer level (meter range: 0-100-percent)- - ! Demineralized water storage tank level-(meter range: 0-100,000 gal) - l
Source range nuclear instrumentation, NI-34 - ' (meter range:.1 to 10,000 counts per second) > Metering pump suction valve CH-A0V-278 selector switch- - Metering pump speed control key lock transfer switch - - Metering Pump speed control (25-100 percent) Air Damper Control Panel -- The following are equipment changes in the "A" switchgear room.
Removal of the old "A" battery -- ,
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_ _ , . .. ? -- ',Redesignate the old "A" battery as battery "C"'withithe;followingf oads:
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J + [ l APPENDIX C
, PROBLEM REPORTS AND CORRECTIVE. ACTION 1, 480 Volt Load Center Breakers Deficiencies 1' The NRC was informed by letter on April 4, 1989,.in a_10 CFR Part 21 l report that the ASEA Brown Boveri Inc. 480V Load Center Circuit Breaker, Model Nos. K-3000 and K-1600 used in Bus 11, had 11 defects in various ' combinations on 11'of 13 breakers.
The licensee and the vendor have
completed corrective actions necessary to restore the 480V. load center to l a design condition suitable for initial energizing and testing. An j additional' defect was discovered after the repoit was made. This defect ' was discovered after extensive breaker testing.
The breaker charging ~; motor pawl became disengaged allowing the. spring to discharge, and preventing breaker operation.
The pawl became disengaged because'it was missing a bearing sleeve.
This breaker,is now designated as a spare breaker and the licensee is awaiting parts.
, The vendor ASEA Brown Boveri (ABB) responded to thes10 CFR Part 21 report i , by letter to the NRC on June 8, 1990.
Specific. responses given were.in ' ' the same sequence as listed by Connecticut' Yankee (CY).
l ) The following-problems were attributed to shipping or handling damage: !
Four motor disconnect switches broken l -- Two arc. chutes on one K-3000 breaker broken
-- The following problems were attributed to improper assembly or inspec-i ! tion: I Loose hardware .j -- . Improper control wire terminations ]j -- Missing retaining ring from one side of a pin that connects'the- --- connection rod to the jack shaft.
I Two cracked terminal strips.
] -- l Missing retaining rings on one side.of the pin used to secure the
-- l primary contact fingers in the contact assembly', q The following problems are attributed to improper instruction books or ' [ need for clarification: .l l- ! L Circuit breaker tripper bar load could not be adjusted to the values ! -- in the instruction book.
The values listed were'for the electro-mechanical trip however, the breakers supplied had solid.
, state trip devices.
' I l ' L The arc chute material appears to be brittle causing chips to flake off.
l during breaker operation.
The vendor has instructed the licensee to L f ! -
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Appendix-C
, continue using the existing arc chutes while the vendor corrects this material problem.
The' vendor has supplied support to correct the above problems including- < revisions to the instruction manuals.
The licensee has corrected all problems, except the missing bushing that; allowed _the charging spring motor pawl to become disengaged, and has completed the testing of thei breakers.
The inspector ~ concluded that the licensee's corrective action.
for the above problems is adequate.
' 2.
480V AC Motor Control Center Molded' Case _ Circuit Breakers Misapplication , The licensee submitted, by letter dated October 20, 1989, a Licensee-Event Report.50-213/89-016 in accordance with the requirements of 10 CFR Part 50.73 concerning installed breakers in MCCs.
A number of breakers, ' located in three motor control centers (MCCs), had current interrupting ratings of 14,000 amps (symmetrical) where the. available fault currents at the breakers ranged from 19,634 amps to 22,524 amps.
< ' t The licensee corrective action was the. replacement of the incorrectly rated breakers with properly rated breakers.
This replacement was controlled by Plant Design Control Record (PDCR)-983.
This replacement also included those breakers whose records were not traceable.
The calculated available-symmetrical short circuit currents at the' l following MCCs are as-follows: Motor Control Center Current (amps)- i 5 bus 5-5 22,524 5 bus 5-6 21,640-i 6 bus 6-6 22,066' l 6 bus 6-7 20,652 8 bus 8-5 19,747- ' 8 bus 8-6 19,634 The following are Westinghouse breaker types and their_ symmetrical i-interrupting rating at 480 volts: Breaker Type Rating (amps)
HMCP 65,000 L HFB 25,000 ! ' HFB 25,000 HF0 65,000 L FA 14,000 l FB '14,000 .
l
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,. , . Appendix C
r , a The following are the number of breakers of type FA or FB that were-replaced with type HFB in the following MCCs: Motor Control Center Number of Breakers t
8
16
15 ' The following is the number _of breaker of type FA or FB that were re- '! placed with type HMCP in the following MCCs:
Motor' Control Center Number of Breakers
5
6 l'
8
The following is the number of break'ers of type FB or HFD that were replaced with type HMCP or HFB because the replace breakers traceability of Class IE could not be established: Motor Control Center-Number of Breakers
8
2
1-The available fault currents were calculated as a three phase (bolted) fault condition with zero impedance at a fault located on the load side of the molded case breaker, Almost all of the breakers were associated-with motor starters.
The fault current would have had to occur between the molded case breaker and the motor starter in order for-.the fault current to be at the magnitude calculated.
If the fault were after the-motor starter, the fault current value would be fur,ther reduced because of the starter contact and thermal heater impedance. The licensee.did . not take credit for this impedance and replaced ^the breaker with breakers , with the minimum fault current as was originally'specified.
The root cause of this problem identified.in LER 89-16 was a design. control deficiency during the time period after the plant received its operating license and into the 1970s.
The inspector discussed this root
, cause determination with the licensee and reviewed the Westinghouce purchase specification for MCC 6 buses 6-6 and 6-7.
This specification listed all load breakers as type HFA. Therefore the inspector agreed ~ with the licensee that there is a high probability that breakers _ type FA - and FB were introduced after the MCC were' installed.
Original compart-ments on MCC 6 that were specified as either future or spare had starters removed and breakers added.
7,.1 ' + Appendix C-
., , i The inspector has concluded.that the licensee has identified the correct root cause of the problem and has provided adequate corrective action and the present design control would prevent a reoccurrence.
3.
125 Volt DC Bus Breakers Trip Response Deficiencies The licensee has identified in Plant-Information Report 90-102, dated-February 15, 1990, that some-125 volt d.c. molded case breakers trip ' responses were not acceptable. The licensee had elected to replace all.
. the 125 volt d.c. breakers-in Panels "A" and "BX" because of trip drift,
._ the age of the breakers, and the unavailability of replacement _ breakers.
This replacement was controlled by'PDCR 995, i The technical evaluation, dated June 2, 1990,_ concluded that the upward-drift, while not desired, resulted in greater assurance against spurious-i 'and premature tripping of essential loads.
Coordination with the up- -stream battery to bus breaker was not compromised. _Therefore, the-licensee concluded that an unsafe' condition did not exist that required reporting to the NRC.-
The inspector concluded that the li nsee has used good judgment in replacing the_125 volt d.c. breakers in panels "A" and "BX" and the licen,ee did not have to report this problem to the NRC.
1_25 Volt DC Bus Breakers Load Derating 4,
The licensee identified in PIR 90-94, dated March 27, 1990, that the, b'eakers on Bus "B" did not include-the load derati y, determined by NJTHERM, which resulted from environmental. testing.
The licensee initiated Reportability Evaluation-90-12 and' performed an engineering evaluation of actual connected loads verses the derating values.
The licen,ee concluded'that-this omission of derating values:was not reportable and the breaker loading was acceptable.
However, the licensee noted that the environment in which the breakers were tested exceeded the "B" switchgear environment.
The licensee has requested the a vendor to supply breaker load deratings that represent the "B" switchgear room environment. -The inspector concluded _that the: licensee: corrective action is adequate.
5.
Type HMCP Motor Circuit Protection Device Trip Set Point
The licensee in a PIR number 90-95, dated May 11, 1990, identified that the trip settings of breakers type HMCP, used in MCCs for motor operated valves (MOVs), cause the breakers to trip.
The involved MOVs SI-M0V-903 a'nd -904 were installed under PDCR;931.
SI-MOV-901, -902, -854A and-854B were installed under PDCR 854.
The wiring and controls for these valves were installed under PDCR 907 "MOVs for ECCS Small Break LOCA."- PIR 90-95 only referenced PDCR 931.
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Appendix C 5- , The Westinghouse brea(er HMCP trip setting was in accordance with recom-mendations given in Westinghouse " Breaker Basics," a working manual on molded case circuit breakers, Third Edition, B-220.
The trip setting
- ,hould be from 9.to 12 times the motor running current.
The licensee had set these trips at 10 times'the motor running current as shown on the circuit breaker setting sheets dated. June 30, 1989. During the testing of the MOVs, the 480 volt load center voltage was at 500. volts.
There - fore, the 440 volt MOV motor voltage was 5 percent higher than= normal, a but within its upper design limit of 10 percent.
However, the vendor recommendations for setting the trip at 10 times running current may be adequate for a constant speed motor that would have a lower inrush current during starting if.the voltage was higher.
This condition would' not be correct for an MOV because the motor is de-
signed for constant torque.
Therefore, the starting inrush current would.
, be higher if the voltage was higher.
Also, the HMCP type breaker trip-i ping time is one cycle compared with the original type HFA breaker that trips in six cycles.
The licensee corrective action was to' change the trip setting of the ' } breakers for SI-MOV-901 and -902 to 12 times the running current as: shown on the circuit breaker setting sheets, dated May 10, 1990.
Retest.of the valves indicated that there were no further trips with the new setting, i P0CR 983 for 480 volt molded case breaker application has a design input that the instantaneous trip of-all breaker types be set at 12 times the full load running current (FLC).
, Following additional review the licensee-has proposed a new set point which is 210 percent of locked rotor motor current (LRC) instead of.the 12 times FLC. The licensee has described the motor circuit protector setting philosophy in a memo from W. H. Becker/J. Chiloyan to G. H.
Tylinski, dated July 2, 1990..The HMCP breakers will have their set point adjusted to 210 percent of LRC.
The inspector concluded that the licensee has provided a proper basis for ~ ' the new set point which includes: voltage elevated to 10 percent, asymmetrical current, and accuracy. This set point should provide adequate electrical. protection, but also allow the MOV to complete its protective function without improper breaker tripping' The previously . identified unresolved item (UNR 90-08-02) is resolved.
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- APPENDIX 0:
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> 'BATTERYJSVRVEILLANCE,1 MAINTENANCE:and TEST PROCEDURES ~ '! , , . I ' . , , PROCEDURE-TITLEc REVISION '
, . LSUR 5.5-16 - Weekly l Station Battery Checks-12, - - < , i ~"A"; Battery: -Junei21, 19906 i(
"B"? Battery: June 21, 1990 s! SVR5.5-17I Quarterly' Station!B'att'ery Checks -.10
- --F
' - , ' -!'A". Battery : l0ctober 14,11989 ' - "B"' Battery-cSeptember.17',1989c j . d PMP 9.5-129 Performance Test of Station 3 Batteries' 3' } - "A" Battery September 20,L1989- "B" Batteryc TJune,18, 1990- ,i J PMP 9.5-145 Station Battery Resistance Test and: .11' ' Rack Inspection.
9a "A" Battery.
April 27L,1990'.
' , "B"LBattery
- Aprily27,.1990
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APPENDIX E . ' SPECIAL TESTS ST 11.7-14 Appendix "R" Service Water Performance-Test Purpose: To demonstrate the ability of the service. water system ~to, support the emergency diesel generators (EDGs),' containment air.
recirculation coolers, and residual heat removal during the.most restrictive Appendix ".R" configuration.
Test performed' January 30, 1990.
Retest performed. July 11, 1990.
ST 11.7-15-Pre-Fuel Load "B" Switchg' ear Room Corrpliance Test Purpose: To verify the ability to ach'ieve HOT SH'JTDOWN condition in the event a fire occurs in any part of the plant excapt~.the "B" Switchgear . Room.
~
' Test performed May 13,11990, ST 11.7-13 "B Switchgear Room Compliance Test Purpose: To verify the ability to achieve: HOT SHUTOOWN condition in the-event a fire occurs in the "B" Switchgear-Room.
" -Test performed June 23,'1990.
ST 11.7-12 1989 Refueling Outage Plant Integrated Test Purpose: To demonstrate the correct integrated response-.~of all'modifica-tions which impact the reactor protection, core cooling, and containment-isolation systems prior to entering Mode 4 at the completion of the 1989 refueling outage.
Section 6.1 verified the electrical independence'of Train'"A" AC and DC power from Train "B" power supplies.
Test of Train "A high containment pressure (HCP) signal and safety injection actuation signal (SIAS) to cause the reactor to trip and actuate the "A" engineered safety feature (ESF) systems.
Electrical power for Train "A" was-supplied from off-site.
The AC and DC power for Train "B" was deenergized for this test.
Test performed June 25, 1990.
, i
..... r Appendix E
q Section 6.2 tested Tra.in "B" similarL to test section'6.1 with the power removed from the "A" electrical systems.
Electrical power for Train "B" supplied from off-site.
Test performed June 25, 1990.
, Section 6.3 tested Train "B" with simulated accident (HCP/SIAS) with Train "A" power deenergized.
Test performed June 26, 1990.
Section 6.4 tested Train "A" with simulated accident- (HCP/SIAS) with-Train "B" power deenergized.
Test performed June 26, 1990.
l ! Section.6.5 tested Train "A" and "B" with loss of off. site power-(LOP).. - Test performed June 27.,>1990 Section 6.6 tested Train "A" and "B" with simulated' accident (HCP/SIAS) , followed by a LOP. This test verified that the systems required to ' operate for a design basis accident and LOP are powered from the> EDGs, Test performed June 28, 1990.
The following discrepancies occurred during these tests: ST 11.7-12, Section 6.1 During the closing of SI-MOV-861C,-the molde'd case breaker supplying 480V power tripped open. This breaker,' type HFA, has been replaced , l by a type HFB breaker (later model).
The removed breaker will be analyzed to determine if the trip setpoint had changed..to cause the trip condition.
The MOV-functioned correctly for the three tests that followed.
This breaker action may have been associated with the unexpected opening of Type HFA breakers which is discussed in section 2,3.5 of this report.
ST 11.7-12, Section 6.3 During the loss of normal power the "A" and "B" emergency diesel generators (EDG) frequencies were 61 Hertz instead of 60 Hertz.
During bus loading from EDG "A" the generator voltage and frequency indicated abnormal swings. When the EDG "A" was being-synchronized to the system, prior to being shutdown, the-movement of the syncro-scope did not appear to be normal and the operator had difficulty synchronizing the generator with the syste _ . s.
a ' f t ( Appendix E
. ~ 'The following day, during preparation for EDG "A" operability testing,.the EDG output breaker could not be closed.
The cause was determined to be the set point of the synchronization check relay.
A defective potentiometer was replaced in the governor circuit. The-licensee noted that after-one hour running-unloaded, the machine speed started to oscillate.. The vendor representative was unable to determine the cause of the problem.
The licensee ran the_EDG "A" both unloaded and loaded. The. machine performed satisfactorily.
The "A" battery charger current oscillated between 50 and 100 amps.
The inspector was informed that this was a condition observed when the battery charger was self-limiting.
The licensee also noted this-condition when the DC breakers were being changed and DC power _was supplied to shorted emergency lights in the Primary Auxiliary Building.
During this test the 200 amps: charger would only be , required.to supply normal 50 amps and 100 amps emergency lighting ' loads and should not be in a self limiting condition.
ST 11.7-12, Section 6.4 , Prior to the final test, the_ "A" battery charger was supplying 1 50 amps at.132 volts. When the LOP was initiated, the battery charger failed.
The vendor, Westinghouse Electric, investigatedLfailure and effect repairs to_the charger.
The inspector concluded that_the special tests conducted-by=the licensee adequately assure the independence of redundant safety related systems and components and that these systems will function as required by the Technical Specification and the UFSAR commitments.
The deficiencies W observed during the test were adequately resolved by the licensee.
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