IR 05000352/1990017

Insp Repts 50-352/90-17 & 50-353/90-16 on 900522-0701. Violations Noted.Major Areas Inspected:Plant Operations, Radiation Protection,Surveillance & Maint,Emergency Preparedness,Security,Engineering & Technical Support

ML20058M608
Person / Time
Site:	Limerick
Issue date:	08/03/1990
From:	Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20058M601	List: IR 05000352/1990017 ML20058M598 ML20058M603
References
50-352-90-17, 50-353-90-16, NUDOCS 9008100210
Download: ML20058M608 (21)

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U.S. NUCLEAR REGULATORY COMMISSION.- -!

     . REGION 1
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Report No ~- 90-17 '

   -90-16
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Docket Nos. - 50-352 50-353  ;

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1 License Nos. - NPF 39

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NPF-85

 . Licensee:
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Philadelphia Electric Company -

.    ' Correspondence Control Desk   ,

P.O. Box 195: l _-Wayne, Pa 19087-0195 + Facility Name: Limerick Generating Station, Units 1 and 2 a

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 -Inspection Period: May 22 - July 1,1990 3-
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Inspectors:

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T. J. Kenny, Senior Resident inspector ', L. L." Scholl, Resident inspector

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M. G. Evans, Resident inspector

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 : Approved by: ~

MA -- 8[?/fa jn,12W 6nceJ TpDoerflein, Chief, Projects Date f~ section 2B- > ,, Insoection Summary: This inspection report documents routine and reactive inspectic,ns

 , during day and backshift hours of station activities including: plant operations; radiation n ~
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protection; sun'elllance and maintenance; emergency preparedness; security; engineering and: r technical support', and safety assessment / quality verification.

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 '9009100210 900G03 PDR ADOCK 05000352     I O  PDC

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 . ELecutive Summary -
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  : Plant Operations (Modules.71707, 71500, 93702)-~    -

f A violation for failure to follow procedures involving control rod movement during a shutdown of Unit I was identified. Root cause analysis and corrective actions already- , performed by Philadelphia Electric Company (PECo) have satisfactorily addressed all , concerns in this area. Additional operational concerns identified during the period included inappropriate actions taken by an' operator in response to condenser vacuum alarms,' and - i

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weaknesses in general shutdown procedure GP-3 identified during a Unit 2 shutdown, i 1'

  . Radiological Protection (Module 71707)

Good practices in tracking and reporting radiation exposures and an effective ALARA program were noted.- Surveillance and Maintenance (Modules 61726, 62703, 61720, 62700, 62702, 62704, 73756) ,

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Inadequate testing of safety related pumps in accordance with the IST program resulted in a violation, During witnessing of main steam line radiation monitor testing and review of the

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events surrounding a loss of shutdown cooling event during an I&C surveillance test, the inspector noted several ietances of improper procedure use and inadequate attention to detai . b; Inspector review of the licensee's maintenance program indicated that the corrective and preventive maintenance backlogs are maintained by the licensee at a number and significanc >! which does not adversely impact safety system operability and availabilit '

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Engineering and Technical Sunport (Modules 71707,73756,90712,92700,92701) The licensee identified incorrectly rated fuses in the 250 volt DC circuits, prompting concern that nonsafety related loads might not be isolated from the safety busses as designed. PECo t performed a Safety Evaluation and replaced most fuses. However, due to replacement fuse-unavailability not all circuits have been corrected. A licensee Safety Evaluation was .i developed to justify continued operatio Instrument tubing installation errors were identified and corrected by the license . The IST program violation discussed above was due to imene application of ASME Section %g _ XI guidance by the Enginering Department. PE.Co has addressed pa:S of this cc:.cen , y however, additional action is needed to clme out this issu L f L 'J . q

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  - Safety Assessment /Ouality Verification (Modules 71707, 30703, 35502)
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The resident inspectors established'a monthly dialogue. meeting with QA management to , review and discuss problem areas and new initiative .

  . The inspectors identified several concerns with the use and content of procedures. In    >
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addition, the inspectors continued to identify concerns regarding the adequacy of the technica M _

  . justifications written by NED in support of site operation >   .
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DETAILS 1.0 . Plant Ooerations

  - At the start of this report period both units were operating at 100% powe !

t Unit 1 On June 1, Unit 1 power was reduced to approximately 50% to perform a control rod -

#' ~  pattern adjustment. Power was increased to 100% on June 2 after satisfactorily ;
  . completing the rod pattern chang On June 4, Unit I was shutdown due to problems with maintair,ing main condenser -

vacuum and the failure of the EHC system permanent magnet generator. Refer to section 1.2 of this report for details of the Unit i shutdow . t l' Following a 16 day mini outage, Unit I achieved criticalits at 1:50 a.m. on June 2 < However, on June 23, while at approximately 60% reactor power, the unit was

  ' shutdown due to a leak in the instrument gas supply to the 'D' main steam isolation valve. Refer to'section 1.3 of this report for details of the Unit I shutdow . On June 28, following a five day outage to repair the instrument gas leak and.various
  - other equipment,- Unit I achieved criticality at 4:15 p.m. At the end of the inspection +

period, Unit I was at approximately '8% reactor power and holding, due to Low

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. Pressure Coolant injection system instrumentation problems, which are discussed in h _ Section 4.1 of this report, i Unit 2 j

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On June 4, Unit 2 power was reduced to 50% afte, a leak was discovered in the d electro-hydraulic control system (EHC) piping to the number 4 turbine control valv ,,

  'Following repair of the EHC piping leak, Unit 2 returned to 100% power on June 1 j

Due to an oil leak on the '2A' recirculation pump, the licensee had planned a Unit 2 L ' shutdown on June 22 for repairs. However, due to reduced radwaste capacity i

- resulting from'a head leak on the '2E' Condensate Filter Demineralizer, management decided.to shutdown the unit on June 21. This shutdown was witnessed by the

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inspector and is discussed in Section 1.4 of this report. At the end of the inspection period, Unit'2 remained shutdow l.

! N Reoortable Events

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Unit I and Common l L On June 6, following the de-inerting of the Unit I drywell, the standby gas l- .. 1 -

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treatment system'_(SBGTS) wasn't restored to normal. Due to the operator' failure to use the system operating procedure (S76.1.c, *SBGTS and RERS Setup for.. Automatic Operation"), the SBGTS filter control hand switches 'HS-076-013A and B'.were inadvertently placed in the .' auto' position versus the  ! correct.'open' position. This mispositioning went unnoticed until a Technical .l Specif; cation hand switch verification check was performed on the midnight H shift of June 7. System engineers were contacted to determine'whether the , SBGTS vas operable with this lineup. On June.8, testing was performed and

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it was dett.rmined that the SBGTS filter valves would not have opened to create' a flow path Mr the SBGTS in this configuration, thereby making the SBGTS - 1 inoperable for she time period the filter handswitches were in the ' auto' 1 position (approximately 14 hours). Corrective action included counseling of-r '

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the operator on his accountability for the use and content of procedures. In addition, the isolation valve handswitches have been marked to indicate the - , normal position and these positions were included in~ the drywell de-inerting  : procedur >

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On June 13, PECo determined that they had failed to maintain in effect the  : provisions of the Fire Protection Program as described in the Fire Protection l Evaluation Report (FPER). Failure of improperly rated fuses to isolate a . postulated electrical fault could have led to the loss of D! vision I DC power , resulting in the loss of Safe Shutdown Method (SSD) 'C'. . A' one hour roving

 . fire watch was established in the affected fire areas in Unit 2 to minimize the
 ' potential that a fire could result in the postulated damage. Unit 1 was in cold i  shutdown condition and SSD method 'C' was not required, so a fire watch was not necessary. This' issue.is discussed further in Section 4.1 of this repor Unit 2
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p There were no reportable events for Unit 2 during this rcport perio . L: ,

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The above events were reported to the NRC via the Emargency Notification I ' System (ENS) and the root cause analysis and corrective actions will be ' L reviewed further upon issuance of the Licensee Event Reports as part of the S j routine inspection progra .2 ' Unit i Shutdown J l1

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On June 4, a Unit I shutdown was initiated when problems were encountered H with maintaining main condenser vacuum. While power was being reduced in , , response to the vacuum problem, the permanent magnet generator (PMG), f which provides a source of control power for the EHC system, failed. The normal power supply is provided by an uninterruptible power supply and the PMG provides a backup power source. The loss of both power supplies would i

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 - result in a turbine trip without the turbine bypass valves. The PMG is geared .
 - to the main turbine thus requiring the turbine to be shutdown to facilitate' i repair .
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1.2.I' .CMLrol Rod Miscositioning

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During the plant shutdown several control rods were left in positions which l were not in accordance with the reactor maneuvering shtitdown instructions, t This condition was a result of the manner in which procedures OT-116, " Loss of Condenser Vacuum," and RE 201, Appendix B, " Reactor Maneuvering -) Shutdown Instructions," were utilized by the plant operators during the -i transien i in the event of a decreasing main condenser vacuum OT-ll6 directs me ' 1 operators to reduce reactor power in accordance with the reactor antneuverin shutdown instructions until vacuum stops decreasing. The method of reducing reactor power is as follows:

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1) Reduce power to 850 MWe or by 100 MWe, whichever is lower, by - reducing reactor recirculation system flo ) Continuously insert specified control rods to the RE-201, Appendix B, target positions to further reduce powe ) Reduce recirculation flow to 45%. 4) Insert a second group of control rods to the specified target positions. - 5) Enter the rod worth minimizer sequence andl continue to insert control-rods until the desired power reduction is obtaine When the loss of vacuum occurred, the reactor operator decreased power to 850 MWe by reducing recirculation system flow. He then attempted to follow - ,- the control rod insertion instructions in RE-201, Appendix B, however the first L . group of control rods were found to be already inserted to the target positions.

E These rods had been inserted previously under the direction of reactor engineering in order to optimize reactor core power distribution following a rod sequence exchange. When the existing rod pattern did not appear to be consistent with the shutdown ins: ructions the operator asked a reactor engineer, who was in the control room for another task, for assistance. At this point the reactor engineer told the operator that he couki verbally provide to the operator L a rod insertion sequence other than prescribed in the shutdown instructions, L which would drop reactor power more rapidly. The shift supervisor then authorized deviating from the shutdown instructions under the assumption that l I

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I the reactor engineer had the authority to provide an alternate rod insertion _ sequence.J Deviating from the shutdown instructions resulted in the following - ) conditions: ' 1)- Nine control rods were not inserted when required by the shutdown- O instruction . a 2) When the RWM sequence was entered several control rods were' driven + directly to position 00 which was not consistent with the desigriated ; sequenc ;

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3) The above actions resulted in a conuel rod pattern different than . ' , required by the RWM. The licensee elected to manually scram the

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reactor prior to descending below the power level at which RWM was- 1 required to be operabl Although the reactor engineers are permitted to make routine adjustments to ; control rod positions to optimize core power distribution there is no allowance tin procedure RE-201 to permit deviating from the shutdown instructions during , a transient. Thus the actions taken during the shutdown constitute a violation -

 "of plant Technical Specification 6 ..81 which requires the plant to be operated in accordance with established procedures (50-352/90-17 01).

Following the shutdown PECo established a team to review the incident in torder to determine the root cause and any corrective' actions to be taken to-prevent recurrence. Based on this review, instructions were given to the reactor engineers and the licensed operators to strictly adhere to the shutdown instructions when responding to a transient. Also, reactor engineering has ' committed to maintaining the shutdown instructions such that they are a consistent with the existing rod pattern to avoid the potential for confusion. - The inspector reviewed the root cause analysis and the corrective actions already performed and determined them to be appropriate and complete. In addition, on June 13 a telephone conference was conducted with NRC Region I management'during which the Plant Manager presented the preliminary results of PECo's review of the event. Therefore, no written response to this 3 violation is require , 1.2.2 Vacuum Decrease Without Excected Turbine Trio j

, 1 During the loss of main condenser vacuum transient the indicated condenser vacuum decreased below the nominal low vacuum turbine trip setpoint without the expected turbine trip. The trip setpoint is 22.2 inches Hg and the indication decreased to just below 22.0 inches Hg as read on the strip charts in
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the main control room.7 The operators decided not to manually trip the turbine-

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based upon the very slow rate of vacuum decrease and because it had only ->

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l marginally exceeded the expected automatic trip point, Plant management 1

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present in the control room concurred in this actio <

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The inspector questioned Operation's Department management regarding the s' decision not to manually trip the turbine. The action is not consistent with ! e Administrative Procedure A-7, " Shift Operations," which states _" Automatic

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operations which should have occurred in response to specific plant conditions 1, * '

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will be verified and if found not to have_ occurred will be accomplished _ mamially when possible."

Operation's Department management reviewed this concern and concluded that r

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  'it would have been proper to manually trip the turbine and have subsequently reiterated this policy to the plant operators. Also procedure OT-ll6 has been
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revised to clarify the expected operator response if an indicated turbine trip -

setpoint is reached. These instruments are nonsafety related and do not input .

  -to the reactor protection system. The inspectors were assured that if the trip point which was exceeded was a reactor protection system instrument, the

orator would have manually inserted the trip functio A calibration check of the main condenser vacuum instrumentation was also performed to determme if they were functioning properly. These checks-

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  -determined that the as found vacuum switch setpoints were lower than the
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  - desired 22.2 inches Hg trip point. The as-found instrument setpoints were
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  'between 17.59 and 21.05 inches Hg. The error was attributed to instrument-drift. The original calibration frequency was every seven years but has since-been increased to once every three years. The increased calibration frequeicy .

should minimize the effects ofinstrument drif ! Operations Department management performed a thorough post-event review to ensure any lessons to be learned were identified and incorporated into the appropriate procedures and into the training progra .3 Unit i Shutdown due to Instrument Gas Leak On June 23, Unit I was shutdown to repair a leak '.n the instrument gas supply to the 'D' main steam isolation valve (MSIV). The instrument gas system is ; normally supplied to the MSIV operator by one of two solenoid operated; valves (SOVs). The two SOV arrangement allows the Nuclear Steam Supply Shutoff System (NS4) to be tested (one SOV et a time) without effecting the MSIV position. During the performance of channel 'D' NS4 testing, the 'D' MSIV drifted closed when the isolation signal was simulated. A follow-up investigation by PECo determined that the most likely cause was an instrument

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gas leak which had previously been identified during a drywell inspection. At the time the leak was identified, the operators did not feel it would affect - operation of the MSIV. The SOVs isolate and vent the instrument gas press'ure ' -

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from the MSIVs upon receipt of an isolation signal. Therefore, at no time was there any question that the MSIV could perform.its safety function. Due >

 &   to the configuration of the gas tubing, with one SOV deenergized, the leak--

caused the gas system pressure to drop sufficiently to cause the MSIV to drift -

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*   closed. PECo decided to shutdown the unit for repairs rather than to operate 4    at reduced power with one main steam line isolated. The inspector observed
.    - portions of the testing and troubleshooting and found it to be properly controlled.-

s M Unit 2 Shutdown

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   'On June 21,' Unit 2 was shutdown due to reduced radwaste system capacity resulting from a head leak on the '2E' Condensate Filter Demineralizer, The inspector witnessed the plant shutdown conducted per GP-3, " Normal Plant  .
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Shutdown." During the shutdown the inspector noted confusion among the-shift supervision regarding the appropriate sequence for reducing reactor a power, removing the turbine from service and scramming the reactor. The _

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inspector noted that GP-3 only provided guidance for performing these steps,

&    as opposed to providing the preferred sequence. Following a brief meeting between shift supervision and Operations Department management,.the plant
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',   was shutdown by reducing power to approximately 22% and-manually . J
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scramming the reactor. When the main generator output decreased to g i approximately 50 MWe, the main turbine'was manually tripped, j n , a

$ ',   ; Following the shutdown, the inspector discussed GP-3 and the sequence of 9  3  events with the Shift Manager and other representatives.of the licensee  '!

E operations management. The inspector questioned why GP-3 did not provide a , j

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   . preferred sequence of steps for shutting down the plant, It appeared to the
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inspector that the options available in GP-3 only caused confusion and delay in i' performing the shutdown. PECo management acknowledged the inspector's  : concerns and stated that GP 3 had been revised prior to the shutdown for the last refuel outage in Spring 1989. At that time, numerous steps and notes were

   - added to the procedure due to fuel leakage, in order to minimize the pressure e..+'    transient during the shutdown. These steps provided multiple options intended yf + .y +  '

for use during that specific shutdown and were no-longer applicable. PECo  ! w1 management stated that GP-3 was currently under review and would be revised K ' to include a preferred shutdown sequence prior to the next planned shutdown (September 1990). Operations personnel are aware of the preferred shutdown

1, sequence in the event of an unplanned shutdown in the interim. The inspector had no further questions.

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t Radiological Protection -

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During~ the maintenance outages on Unit I and 2, the Health Physics Department-closely tracked personnel exposures and reported the information at the 8:00 ; Shift Managers meeting. This was effective in keeping management informed of station ALARA program performance and in keeping the other departments b continually aware of their individual ALARA performance,

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 . Surveillance and Maintenance
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The inspectors observed portions of the surveillance testing and maintenance activities - listed below to verify that the test instrumentation was properly calibrated, approved :!

 . procedures _ were used, the work was performed by qualified personnel, limiting !

conditions for operations were met, appropriate system or component isolation was

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provided and the system was correctly restored following the testing or maintenance activit u

 . Maintenance     i Maintenance activities observed and/or reviewed included:
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MRF 9002931 Replacement of Unit 1 Channel 'D' , EWR L-00387 - Main Steam Line Radiation Monitor [a MRF 9080477 Calibration of Unit 1 Main Condenser *

  ' MRF 9080478  - Pressure Switches (Turbine trip on MRF 9080479  Low Condenser Vacuum Instrumentation) y i   MRF 9080480  PS-M2-1104 A, -'l 104B, -1105 A, -1105B,-

} MRF 9080481 -1106A, -1106B j l MRF 9080482  ! N ~3.1.2 Maintenance Program Imnlementation Review a' A review of the maintenance program was performed to determine:

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if the maintenance backlog has any significant impact on the operability ;

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ll of safety systems;

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the trend of the maintenance backlog and the rate at whien the backlog of work is being completed; o P

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safety system outage times and the comparison to unavailability times ! assumed in the PRA;

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ALARA performance for jobs performed in radiation area .

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d 4 -' The inspector reviewed a history of all Unit 1 open corrective maintenance work items and overdue preventative maintenance (PMs) tasks for impact'on system operability. This review was limited to those items affecting safety' systems. At the time of this review there were 12 overdue PMs and l

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 = approximately 280 open corrective maintenance (CM) maintenance request forms (MRFs). - Based on a review of these MRFs and discussions with-
 ; maintenance and system engineers, the inspector concluded that the open work-did not jeopardize safety system operability,   l ij A review'of the open Unit 1 MRF backlog (safety and non-safety systems)- j indicates that the number has remained relatively constant at about _1,000, of ~ j which approximately one half are non-outage MRFs. The trend'of overdue  i PMs has sho_wn gradual improvement and the number of overdue PMs does not j e  appear to be excessive. The number of MRFs completed on a daily basis is 1 approximately ,15 to 20. This performance has been adequate.to prevent the'

backlog from increasing, but not to significantly reduce the total backlog ]a m'mbe ! The system engineers track the out of service times for safety systems and compare these times to those assumed in the Limerick Probabilistic Risk jl Assessment (PRA). Currently, the actual system availability times have been

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approximately 60% of those assumed in the PR l

# The inspector concluded that the maintenance program is' adequate to maintain- :;

safety system operability. The inspector discussed with PECo management the -I fact that balance of plant equipment problems do not appear to uceive a level

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of attention-commensurate with their importance in preventing a plant trip or c transient. Examples of these are stator cooling water system repairs, chronic- '; T' instrument air and instrument gas system problems, and difficulties in-

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l- ' maintaining cooling tower makeup pumps operable. PECo management is 1

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considering these comments and future inspections will document changes y made by PEC .2 Surveillance n , M Surveillance testing observed and/or reviewed included: % N ST-2-042-660-1 NS4 Reactor Level 1 and 2 Division IIB, Channel D 'J ST-2-012-407;l Radiation Monitoring-RHR Service Water Radiation Monitor; Division IV, Channel D Calibration / Functional 1 g Test I o ST-2-041-423-1 RPS and NSS-Main Steam Line Radiation-High, Division l ? IIB, Channel B2/D Calibrational/ Functional Test (RE-41-ll IN0060, RISH-41-lK603D) o m o _..__ - - -____ ___ ____ _ -_ l

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9- '! ST-5-041-879-1 - Determination of Main Steam Line Radiation Monitor: RISH-41-lK603D Setpoints (Alarm and Trip) y ST-2-041 807-1 - RPS and NSSS-Main Steam Line Radiation-High,-

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i Channel D Response Time Test (RISH-41-lK603D) 4 ST-1-072-896-1 NS4 Group VI. Primary Containment Isolation Response

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Time Summation (Partial) ST-1-072-891-1 NS4 Group I Main Steam Isolation Valves Response '

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Time Summation (Partial)- ST-2-042-638-2 - ATWS - Reactor Vessel Water Level - Low Low,- Level; j R 2, Division 2A, Functional Test (LS-X-MI-20134) S T-6. 642-314-1 - ^ D14 Diesel Generator. Operability Test Run - j ST-2-074-623-1 Rod Block Monitor Channel B Functional Test J ST-1-043-321-1 - Reactor Recirculation Motor Generator Set Scoop Tube ! Electrical and Mechanical Stop Test with the Plant .c Shutdown - -

 - ST-6-Ol l-231-0 A Loop ESW Pump, Valve and Flow Test  1 ST-6-055-230-1 HPCI Pump,. Valve and Flow Test ST-6-052-232-l! B Loop Core Spray Pump, Valve and Flow Test  l ST-6-052-232-2 B Loop Core Spray Pump, Valve and Flow Test ST-6-051-231-2 - A RHR Pump, Valve and Flow Test
 ' ST-6-051-232-2 B RHR Pump, Valve and Flow Test   ,i

' ST-6-051 233-1 - C RHR Pump, Valve and Flow Test y ' ST-6-051-233-2 C RHR Pump, Valve and Flow Test - No problems or concerns were noted by the inspectors except as specifically

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discussed belo u 3.2.1 ' Main Steam Line Radiation Monitor Reolacement and Testing The testing on the Unit I channel 'D' Main Steam Line Radiation Monitor was _

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performed following the replacement of the existing instrumentation drawer with an equivalent Numac model. The task was closely monitored by the  !

 ~ Instrumentation and Controls (l&C) Department supervisors, and the  :

technicians were well prepared and displayed a high degree of proficiency in ! accomplishing the testing. An area of concern noted was the administrative 3

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control of the activity The following items were identified and discussed with , members of the I&C staf Section 6.4 of ST-2-041-423-1 requiris the setting of a decade box at 550K ohms and then decreasing the resistance until the INOP alarm is displayed. The step could not be perf(rmed exactly as written in that the alarm was occurring with the box s:tting at 550K ohms and required starting at a higher initial setti ng in order to establish the trip point. The technician noted this proble u in the remarks section of the G

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  : test and then continued performing the remainder of the test. This 1 4   correction should have been accomplishcd by the use of a procedure g   change versus annotation in the remarks sectio f~
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The Numac technical manual. requires a one hour warm up period prior,

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to testing. This was not required by the surveillance test, however one '

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hour had elapsed before the calibration check commence ,j e

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The time response test results did not meet the acceptance criteria of ST-2-041-807-1,~ however the test was signed off as satisfactory. Thi m was based on the fact that this data is only a portion of the overall time

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7 response calculation and, although this test criteria was not met, the i total response time was in fact within the Technical Specification limi < f . A test result evaluation (TRE) was performed to document this +

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conclusion. However, the test should have been signed as unsatisfactory 3 and then the results accepted based on an engineering evaluatio j w

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ST-2-041-423-1 does not provide clear directions on how and when to

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There is no approved procedure in place to provide direction on the use m of the Cesium 137 calibration source. The inspector observed the use

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of the source and noted that the evolution was controlled by a radiation

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work permit'(RWP) which required constant coverage by a health physics technician. Also,'a draft procedure was provided as a work instruction to give direction on how to use the source, however it is not

[*s   clear who reviewed and approved the, work instructio l f  The inspector concluded that with inadequate instructions and less than strict adherence to the established administrative procedures, satisfactory accomplishment of this type of task cannot be assured, particularly if accomplished by less experienced individuals. These concerns were discussed

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appropriate c frective actions.

i, m 3.2.2~ Loss of Shutdown Cooling During Testing a i On June 7, during the performance of surveillance test ST-2-012-407-1,

  " Residual Heat Removal Service Water (RHRSW) Radiation Monitor Channel D Calibration / Functional Test," Unit I shutdown cooling was lost for approximately 30 minutes. Step 6.11.5 of the test verifies that the RHRSW isolation valves to the RHR heat exchanger go closed when the RHRSW radiation monitor Hi-Hi trip point is exceeded. With these valves shut the t l  RHR system does not remove decay heat from the reactor. The loss of cooling
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11 i N was identified by the. Unit I reactor operator when he noticed increasing-

   : reactor coolant temperature and reactor vessel level and reopened the valves.' .

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  .

Reactor temperature increased from 144 degrees F to 169 degrees F and vessel !

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level increased from 90 to 97 inche ,

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The inspector discussed this loss of shutdown cooling event with several PECo : S, , representatives. The inspector pointed out to the licensee that the test should

      .   ,
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not have been performed with shutdown' cooling in operation utilizing thc 'B's RHRSW loop. Instead, the 'A' loop of RHR shutdown cooling should have- 3

   : been placed in operation while conducting the' test which resulted in the 'B

loop becoming inoperable. The first note to Technical Specification (TS) . 3.4.9.2 states that one RHR shutdown cooling mode loop may be inoperable

    ~

for up to two hours for surveillance testing provided the other loop is operable , E and in operation. The Technical Specification limiting condition for operation,

         !

however, was not exceeded because the operator identified the proble # The licensee acknowledged the inspector's concern and stated that the operator authorizing conduct of the test did not realize that the test would result in the

 ,  RHRSW isolation valves to the RHR heat exchanger going closed and the u  I4  subsequent loss of shutdown cooling. The representative stated that this requirement was not clearly stated in the test prerequisites. However, the j inspector noted that prerequisite step 5.4.5 states that performance of the test <

will result in RHRSW. isolation valves receiving an isolation signal. This does

 >
>
  ,  not provide explicit caution that cooling could be lost, but does indicate that

the test may have a significant effec # The inspector noted that step 7.4 of ST-2 012-407-1 was not properly performed, in that the I&C technician performing the test did not verify that ;

,   ,  -the .RHRSW isolation valves to the heat exchanger were restored as per current - !
,
 +. plant conditions; This step was signed off as complete. Proper performance
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of this step would have had the operator open the valves sooner, thus restoring >

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shutdown cooling. Also, the independent verification of restoration (IVOR) ' q was not performed prior to the operator identifying the loss of shutdown ,

"
   ~ cooling. If the IVOR had been completed sooner the time period in which shutdown cooling was lost could have been reduced. The licensee also  f
,   identified these issues during their follow-up revie ,
,

From review of this event and the procedure being utilized (ST-2-012-407-1) it- ' appears to the inspector that the personnel involved in the testing lacked the

'

attention to detail nxded for performing TS related testing. PECo is '

;L   performing a root cause analysis review of this event which will address the i    above concerns. This item will remain unresolved pending additional review of the licensee's root cause analysis and corrective actions (50-352/90-17-02),

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'1   3.2.3 Inservice Testine Procram (IST).

I_ ' During an inspection in March 1988, an NRC inspector noted that PECo was . l.

    ~
  . using. expanded differential pressure range limits for the IST acceptable, alert, '
 '

p < and required action ranges for the core spray pumps. PECo's . limits were ' noted as extending beyond those specified in Table IWP-3100 2 of the ASME _

        !

Section XI Cod : i y' PECo's expanded range position was developed b'y corporate engineering as

K documented in the attachment to their memorandum M February 8,198 ,

l Corporate engineering added instrument accuracy tolerances to obtain the ' broader acceptance range for several pumps including core spray, residual heat L ' removal (RHR), emergency service water (ESW), high pressure coolant > 1  ; injection (HPCI), and reactor core isolation cooling (RCIC). During a;1988 ,

        "

review the inspector noted that this was not in accordance with the Code and . no formal code interpretations were presented to the inspector. The issue was 'i left as an unresolved item (UNR 50-352/88 07-03) pending NRC review of i further justification by the license ,

 >
  ' During the current period the inspector reviewed PECo's response to this issue which included a Technical Section memorandum supporting the use of  ,

expanded ranges for IST pump test parameters, dated August 24,1988. The 1 inspector discussed the issue with. licensee representatives and reviewed recent ,

        (

IST pump test results for the core spray, RHR, and ESW systems. The -  ! inspector noted that PECo was still using expanded ranges for these pumps. In addition,-the inspector noted that recent test results (June 19,1990) for the 2B > RHR pump differential pressure were within the LGS expanded ranges but fell I i .outside of the more narrow code limit ;

 ,

The inspector was provided with a copy of a letter from PECo's Nuclear Engineering Department-(NED) to the Limerick Technical Superintendent dated April 6.1990 which addressed NRC open item 50-352/88-07-03. The letter stated that NED had reevaluated its original recommendations against current-

1. industry practices and proposed code changes, and recommended that the expanded ranges be withdrawn from use and replaced with revised ranges per ANSI /ASME OM-6, " Inservice Testing of Pumps in Light Water Reactors."

This recommendation was based upon a determination that the February 1985 analysis could no longer be technically supported and that the code provision

,   for each owner to expand IST pump ranges was not intended to be applied -
*

generically.on all pumps. NLD's recommendation-for corrective action was to apply the OM-6 allowable ranges which would require a Relief Request being submitted and approved by NRC. The inspector questioned why the expanded ranges were still being used, since engineering had determined that their previous justification could no longer be technically supporte .

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  . In response to the inspector's concerns, NED issued another letter to the Technical Superintendent on Jane 22,1990, retracting the April 6,1990 letter.- ;
'

m NED stating that the previous justification (February 1985) was still technically

  - acceptable, but that ANSI /ASME OM 6 provides a better metho n, y4   While the code allows expansion of the ranges on a case by case basis fo h   components failing to meet the speciDed values, it does not allow generic
  ' expansion of the ranges in advance of component failure. The inspector *
"'
,   concluded that PECo has no adequate technical justification for expanding the
 '

o ranges;; Engineering's recommendation of April 6 and June 22 to use the OM-6 allowable rangs is not feasible at this time since 'a relief request has not ;

 '

9 .been approved. As can be seen by review of Table 1, using the current LGS expanded ranges for the Unit IC RHR pump, the Technical Specification limit . - for discharge pressere will be reached without entering the alert range. With a- t E nominal RHR pump suction pressure of 11 psig, and a minimum allowable '

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discharge pressure of 150 psig (per Technical Speci6 cation) the minimum allowable differential pressure for RHR pump IC is 139 psid, which is within the LGS expanded acceptable rang ' ' By using the ranges allowed by the Code, the Alert range would be entered prior to reaching the TS minimum discharge pressure of 150 psig and the 3 possibility.of pump degradation would be detecte , Based upon these findings, PECo's IST program for pumps appears to be , inadequate in that the discharge pressure of safety related pumps could degrade a' to the TS minimum values without_ being highlighted by the IST progra This is a violation of TS 4.0.5 for failure to perform inservice testing of pumps- ,

        '

in accordance with Section XI of the ASME Code (50-352/9017-02). Based

,

on issuance of this Violation, Unresolved item 50-352/88-07-03 is considered-

        '

m close I In.this case engineering support was ineffective in establishing a technically acceptable and consistent position. Of additional concern is station i engineering's acceptance of the inadequate technical justifications from NE ; This is an ongoing problem previously noted in inspection reports 50-352/88- ; 20 and 50-352/90-15. PECo also views this as an undesirable way of doing

>

business and is seeking a solutio PECo subsequently reviewed the results of the 2B RHR pump surveillanct test a and determined that the pump suction pressure instrument used for data collection during the test was inaccurate. Recalculation of the differential pressure using the correct suction pressure value indicated that the pump was within Code limit + s

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TABLE 1 j r

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     -lC RHR PUMP    '

j ALLOWABLE RANGES OF TEST RESULTS >l PARAMETER - DIFFERENTIAL PRESSURE (Psid) +!

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Acceptable Range - Alert Rang Action' Range - '.

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        .;
  : LGS Expanded 127.1 - 17 LO: 122.4 - 12 : < 122.~4 - ;
,   Ranges ' (.81 x RV - 1.14 RV) ~ (.78.RV -;.81- RV) (,78 RV) .g Hl:- 177.1 - 17 > 17 ;
        "
     (1.14 RV '- 1.1.5 RV) ' (1.15 RV).

'ASME l Section XI 14 . LO: 140.4 - 14 < 14 '! Ranges (.93 RV - 1.02 RV) (.90 RV .93 RV). ( 90 RV) :

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HI:.159.1 - 16 > 160.7 - <

     (1.02 RV - l.03 RV) (1.03 RV) _ j M        3.c'

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1*RV = Reference value = 156 psid

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' Ennineerine and Technical Suncort I Chec TE DC System' Fuse Ratings PECo has determined that the 250 VDC rated fuses in the IE DC distribution
  . system may not be adequate for the installation since the system voltage is as
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R high as 275 VDC when the battery chargers are in operation. Testing of the: i' .; .250 VDC fuses at elevated voltages has determined that under certain fault - ! conditions the fuse may blow and then arc over, possibly requiring an upstream! ;! j - fuse,to blow to clear the fault. During this review several fuses with a 250 A  : VAC rating were also found installed in the DC power divisions. .The 250 ~ f VAC rating is equivalent to 150 VDC. A third concern identified was that ' i L ' some non safety related loads were not properly isolated from the IE DC 5us , in that they should have two fuses in series to ensure clearing of faults without ! e , affecting the remainder of the bus. The origina; design specified a single fus , 4 ' configuration. A modification was performed to add a second fuse to these-

        '

circuits on Units 'I and 2.

u" 1 r PECo performed an engineering evaluation to ensure that the DC systems, with the existing fuses, remained capable of performing their intended function This evaluation determined that operation in this condition was justified until fuses with the proper ratings could be installed. Since the discovery of the l

       .4 problem, both Units 1 and 2 have shutdown for other equipment repairs and at that time most of the fuses with the 250 VDC or 250 V AC ratings were replaced. Several circuits were not reworked due to the unavailability of parts.-

The justification for continued operation remains valid until'the remaining parts become availabl ! l 4.2' Low Pressure Coolant Iniection'(LPCI) System Instrumentation Tubing Errors During the startup of Unit 1, the Division 2/4 LPCI Line Internal Break Alarm

'

could not be cleared. This alarm annunciates when a differential pressure is sensed between the 'B' and 'D' LPCI injection lines. During an investigation ; into the cause of the alarm it was determined that the instrument t^ing for one L side of the LPCI line break differential pressure (DP) transmit' .d the 'B' y' j LPCI injection valve differential pressure transmitter were crot .. The lines l were apparently crossed during a modification to the tubing dunng the last t l' refueling outage. It appears in the past the problem was masked because a ;

       '

slight amount of leakage past the seat of the LPCI injection line check valve L can alloiv the pressure to equalize with reactor vessel, resulting in a zero y differential pressure condition at the line break DP detector. During the p current startup, pressure did not equalize across the check valve quickly enough to prevent a large DP.

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16 . r: ' The tubing was reworked to return it to the proper configuration and all othe

      -work performed during the modification was reviewed to ensure no other
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isimilar errors had occurred. No other problems were identified during thi review. , A Human Performance Evaluation System review is in progress and, the inspectors will review 'ae results of the evaluation.- ,

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;,    : Emergency Service Water JESW) System Pumn Performance (Closed) (50c  ,

352/89-03-0l)  !

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This item identified several' questions concerning the performance of the ES !

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pumps when actual operating data is compared to design specifications. Based on the inspectors questions, PECo decided to have the pump vendor evaluate

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f the acceptability of the pump's performance. PECo and vendor representatives concluded tid following: E, '

      > Although the ESW pumps do not develop the head specified in the (
      -

FSAR pump operation is satisfactory and the developed head is

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sufficient to ensure the design flow rates through the individual ESW . i es system components. Also, pump performance has been consistent with : o no detectable negative tren The system loop flow indicators are operating properly' ,

      -

Following the satisfactory completion of a two unit ESW system flow balance a new reference curve, to be used to determine the acceptability l1 s of pump performance during the inservice test program,-was developed , L .to envelope pump operation for two unit operatio ~"

      --
      - The FSAR emergency diesel generator load tables will be upe..'ed to reflect actual loading as a result of the control structure chiller unit Based on the actions stated above this item is closed.

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     .

i l Safety Assessment /Ouality Verification , The resident inspectors have established a monthly meeting with the QA Department

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managers. These meetings are intended to be an information exchange to: 1) better .i' L understand the workings of the QA department; 2) receive information on recent i audits and assessments performed by the PECo QA department; 3) discuss newly , L issued NRC policies and procedures and 4) discuss generic concerns that have been ( identified at the facility or within the industry. A meeting was held on June 20,1990, and the next is scheduled for July 25,1990.

' The inspectors continued to identify problems with procedure compliance and in the technical adequacy of procedures (see Sections 1.1,1.2.1,1.2.2,1.4, 3.2.1 and 3.2.2. Management attention is warranted to ensure personnel clearly understand the h standards of procedural compliance and to verify the riclicy is implemented.

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 . _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ . _ _ _ _ _

. 3,l',.[6 ) ' i

,
 . The inspectors identified an inadequate technical justification from NED. This justification regarded implementation of the requirements of the ASME code in
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the performance of inservice testing of safety system pumps and resulted in the issuance of a violation (as discussed in section 3.2.3 of this report). As

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 - discussed in Inspection Report 50-352/90-15 and 50-353/90-14 regarding y 1 inadequately dispositioned nonconformance reports, additional managemen n
 - attention is warranted to ensure adequate engineering support for site operations;
# Review of Licensee Event Reoorts (LERs) and Special Reoorts -

The following LERs or Special Reports were reviewed by the inspector and determined to have accurately described the events and to have been properly addressed for corrective or compensatory action:

' Unit 1
.

LER l-90-012, April 26,1990-Inoperability of portions of the Residual Heat Removal (RHR) system-due to an unacceptable physical separation between Class IE and non-Class IE cables within valve motor operators as a result of a drawing deficienc Monthly Operating Report for May 1990, dated June 8,1990 Unit 2 LER 2-90-007, March 30,1990 g[ Automatic actuation of the Primary Containment and Reactor Vessel isolation Control System due to loss of power to the '2B' Reactor Protection System /Uninterruptible' Power Suppl : LER 2-90-008. April 17,1990 i' High Pressure Coolant Injection system inboard isolation valve inadvertently isolated due to the failure of a Rosemount differential pressure transmitter. The HPCI system was already inoperable for scheduled maintenance. The differential pressure transmitter was returned to the manufacturer (Rosemount, Inc.) for failure analysi The transmitter failure is not considered to be related to the failure mechanism described in NRC Bulletin 90-01, " Loss of Fill-Oil in Transmitters Manufactured by Rosemount."

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    '18  ,

Monthly Operating Report for May 1990, dated June 8,1990 g . No additional concerns were identified upon review of the above listed report l Exit Interview-

  ~
 -7.1- The NRC resident inspectors discussed the issues in this report with the >
        [
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licensee throughout the inspection period, and summarized the findings at an e exit meeting held with the Plant Manager, Mr. Martin McCormick on June 29, t

,

1990. No written inspection material, except as noted in Section 7.2,'was

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        >

j provided to licensee representatives during the inspection perio ; Temocrary Waivers of Comoliance ' y

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During the inspection period the inspector provided the licensee a copy of February 22,1990 memorandum from Thomas E. Murley to the five NRC o, Regional Administrators describing the current NRC process for review and

  : issuance of Temporary Waivers of Compliance. The content of the i

memorandum was discussed with the Plant Manager, Operations Superintendent'and the Regulatory Engineer,

, : Additional NRC Insoections this Period
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  ~ The following inspector exit interviews were attended during the report period:

Dates Subject Report Insocctor-

  '5/21-5/25 Emergency Operating 90-80/90-80 .D. Florek  !

Procedures ' (Team leader)

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