IR 05000352/1987028

Safety Insp Rept 50-352/87-28 on 871101-1210.Violation Noted.Major Areas Inspected:Nrc Bulletin 87-002 on Fasteners,Walkdown of Redundant Reactivity Control Sys,Plant Tour & Observations of Maint & Surveillance

ML20147C859
Person / Time
Site:	Limerick
Issue date:	01/12/1988
From:	Linville J, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20147C677	List: IR 05000352/1987028 IR 07100101/2012010 ML20147C669
References
50-352-87-28, IEB-87-002, IEB-87-2, NUDOCS 8801190359
Download: ML20147C859 (27)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No. 87-28 Docket No.'50-352 License No. NPF-39 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, PA 19101 Facility: Limerick Generating Station, Unit 1 Inspection Period: November 1 - December 10, 1987 Inspectors: E. M. Kelly, Senior Resident Inspector L. L. Scholl, Resident Inspector J. H. Williams. 'roject Engineer A. G. Krasopoulos, Fire Protection Specialist Reviewed by: [M H. Williams, Project Engineer

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.s LinvilleM6ief, Pro T s 'Section 2A Da'te /

Summary: Rout e daytime (178 hours0.00206 days <br />0.0494 hours <br />2.943122e-4 weeks <br />6.7729e-5 months <br />) a backshift (16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> including weekends) inspections of Unit 1 by the resident inspectors consisting of (a)

resolution of outstanding items including response to NRC Bulletin 87-02 on fasteners; (b) walkdown of the Redundant Reactivity Control System (RRCS),

plant tours, and observations of maintenance and surveillance; and (c) review of LERs and periodic report Events followed included several reactor enclosure isolations during the period and a feedwater level transient on November 19. The inspectors noted that prompt reactor operator response to the feedwater transient prevented a reactor scram and reflects well :n ;,imulator trainin Meetings attended included routine Plant Operations Review Committee (PORC), Electro Hydraulic Control System (EHC) evaluations, a Unit 2 SALP meeting on December 7 and a Nuclear Review Board (NRB) meeting on December 10, 8801190359gBMN525 PDR ADOCK PDR

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One violation was identified (Detail 3.2.1) concerning isolation of fire water suppression valves without appropriate supervisory authorizatio Two licensee identified violations involving surveillance testing are discussed in Detail 5.2.2. An example where the licensee's activities in the assurance of quality were not effective in correcting internal panel wiring errors as well as notable examples of effective worker performance and management critique of personriel errors, are discussed in Detail 8.

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~1.0 . Principals Contactqd Philadelphia Electric Company

. J. Doering, Superintendent of Oparations R. Dubiel, Senior Health. Physicist

.G. Edwards, . Technical Engineer J. Franz, Station Manager J. Grimes, Branch Engineer, Testing and Labs J. Milito, Field Engineer D. Helwig, QA Manager J. Spencer, Superintendent of Services

Also during this inspection period, the inspectors discussed plant status and operations with other supervisors and engineers in the PECO, Bechtel and General Electric organization .0 Followup on NRC Bulletins and Unresolved items

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2.1 NRC Bulletin No. 87-02; Fasteners-In response to NRC Bulletin 87-02, Fastener Testing to Determine

, Conformance with Applicable Material Specifications, the licensee

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began planning for selecting a sample of fasteners to be tested as required by action number 2 of the bJiletin. The inspector reviewed the. selection process being used to ensure a diverse sample of various grades and sizes of fasteners. The~ inspector also ve.ified .

that the licensee selected the ample in approximate proportion to the in plant use of each type of fastener. The inspectcr noted-consistent communications between the licensee's Unit 1 and Unit 2 organizations so that there is no Juplication and a. minimal amount of overlap in the types of fasteners to be teste The final selection of specific fasteners to be tested and subsequent test results will be reviewed by the inspector in 6 i subsequent repor .0 Plant Operations 3.1 Summary of Events Unit I was l',aited te operation at 85% power until November 2 Main turbine elec'..onydraulic control system instabilities were eliminated on November 21 by installation of a notch filter which anebied operation at 99% power. An instab'lity of the number 3 main turbine control valve, requiring adjustment of a function generator card, prevented full licensed power from being achieved until the i

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end of the ~ inspection ' period. A feedwater level transient occurre on November-19 (Detail 4.2).

3.2 Operational Safety Verification 3. ; Control Room Act_ivities The inspectors toured _the control room daily to verify proper ,

manning, access control, adherence to procedures and compliance with technical specifications. The inspectors reviewed shift superintendent, control room supervision, and licensed operator logs and records covering the entire inspection period. On December 8 and 10, back3hift inspections were performed between the hours of 2:00 am and 6:00 a The inspectors reviewed logs and records for completeness, abnormal conditions, and significant operating changes and trends. Other records reviewed included: reactor engineer and shift technical advisor (STA) books, night orders, radiation work permits, the locked valve log, maintenance request forms,

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temporary circuit alterations, and ignition source control checklists. The inspectors also observed shift turnovers during the period. Operations activities were observed to be in conformance with Administrative Procedure A-7, Conduct of Plant Operations, with the exception of the removal from service of fire equipment described belo .

On November 16, a reactor operator issued blocking permit

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number 7025 to isolate hose reel number 119 in the turbine

,: etcInsure for repairs. The permit closed header isolation valves 0058 (normally open) and 1106 (normally locked open)

resulting in the isolation and inoperability of 17 fire hose

' stations and fire suppression water to the standby gas treatment and centrol room emergency fresh air system filters.

The reactor operator failed to obtain shift supervision review

' and approval of the permit as required by the plant administrative procedure. Fire protection equipment was rendered inoperable without implementing compensatory measures.

Administrative procedures for the control and operation of locked valves were also violate The isolation valves were closed from 1

00 a.m. until 5:15 at which time the shif t supervisor became aware of the evolution and directed the valves be reopened. The failure to follow Administrative Procedures A-8 for the control of locked valves and A-41 for removing technical specification equipment from service is a violation of Technical Specification 6. which requires the implementation of procedures for the control of plant equipment (50-352/87-28-01).

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. s discussed in section~8.2 of this report'a PORC meeting was held to review'this and various other instances of personnel-error in an effort to identify and correct any root causes which may be contributing to a higher error rat . Security-During entry to. and egress from the Unit 1 protected area and vital areas, the inspectors observed that access controls, security boundary integrity, search activities, escorting and-badging were in accordance with Security Plan implementing procedures and guard force instructions. The inspectors also observed the availability and operability of security' systems such as search equipment, perimeter detection devices, a'nd-security computer alarms. The inspectors verified that the minimum number of armed guards required by the Security Plan to be onsite were present on selected shifts by review of duty rosters, discussion with licensee Shift Security Advisors, and observation of guard force turnover No violations were identifie .2. Guard Force Drug Testing

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Th'e inspector was informed by licensee security management of a Protection Technology Inc. security force member whose employment was terminated on November 18 for drug use. The individual had been a watchman on the Unit 1 guard force for the past 20 months. During routine drug screening which was part of the watchman's annual physical on November 12, the physician conducting the testing noticed an unusual clarity and

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low pH of the individual's urine sample. A second' test sample

was taken and the results (using gas mass chromotography techniques) indicated positive for cocaine byproducts. The watchman's Unit 1 protected area access was restricted on November 12, an employment termination interview was conducted on November 18, and the Nuclear Employee Data System was notifie .2. Drug Investigations As a result of ongoing drug investigations on site, negative drug test results were received for four janitorial personnel tested on November 6. An additional person was interviewed on November 9, admitted to drug use, and had his employment terminated. Positive test results were received for a sixth l Janitor, badged for Unit 1 protected area access since September 1987, who admitted to recent marijuana use offsite.

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l Licensee investigators interviewed another janitor on November l

12 implicated during the investigation as a potential drug i dealer. That individual admitted to cocaine sales. Some were inside of the Unit 1 protected area but principally were from l

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his vehicle in the parking lo The sales were primarily to laborers and other janitorial personnel. The individual who admitted to selling cocaine had been badged for Unit " access

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for approximately three years and had stated that he was not a user. His employment was terminated by his onsite employer on November 13 and, his name was provided to local law enforcement authorities. Additional interviews of.that individual by licensee investigators are planne The resident inspector was apprised of the above information by the licensee on November 13 and November 16, and determined that the licensee's actions were in accordance with the PEC0 fitness for duty progra . Radiological Controls The inspectors observed the availability and use of radiation monitoring equipment, including portal monitors and portable friskers. The inspectors also observed health physics (HP)

supervision and technicians in plant activities involving potentially significant radiological conditions. Radiation work permits (RWPs) were selectively reviewed to determine that

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appropriate job controls, protective clothing, dosimetry and HP support were prescribed, in use, and understood by workers involve Radiological controls for posted radiation and contaminated areas were assessed as part of the inspector review of selected RWP Proper surveys and contamination clothing were prescribed. Radiological conditions were discussed with HP technicians. Proper locked high radiation area controls, including appropriate and frequent surveys, were verified to be employed. The inspector had no further concerns, and identified no violation .3 Station Tours The inspectors toured accessible areas of the plant throughout the inspection period, including: the Unit I reactor and turbine-auxiliary enclosures, the main control and auxiliary equipment rooms; battery, emergency switchgear and cable spreading rooms; the spray pond pumphouse; diesel generator cubicles and the plant site perimeter. During these tours, observations were made of potential fire hazards, radiological conditions, housekeeping, tagging of equipment, ongoing maintenance and surveillance, and the availability of required equipment. No unacceptable conditions were identifie . - . - . - _ _ _ _ _ _ _ _

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3 3.4 Safety System Operability 3. RRCS Verification The inspector performed a detailed walkdown of the redundant reactivity control (RRCS) system in order to independently verify system operability. The walkdown included review of the following:

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Technical Specifications, Final Safety Analysis Report (FSAR) Sections, P& ids, and Licensed Operator Training Plan RRCS equipment conditions

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Status of control room indicators and controls

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Complete surveillance test The inspectors discussed recent maintenance, modifications, and design concerns related to the RRCS with responsible reactor and I&C engineers. Proper operation of the RRCS was also verified from a review of the post-trip alarm log and the sequence of events printout from the September 19, 1987, reactor scram even No unacceptable conditions were note . PRA-Based Inspection of HPCI The inspector performed a high pressure coolant injection (HPCI) system walkdown utilizing methods prescribed in a study prepared for the NRC by Brookhaven National Laboratory using the Limerick Probabilistic Risk Assessment (PRA). The study, entitled PRA-Based System Inspection Plan, dated May 1986, provides inspection guidance by prioritizing plant safety systems with respect to their importance to ris The study incorporates abbreviated system checklists which contain components that are considered to have a high contribution to risk as determined in the PR The inspector verified the proper operability or configuration of the following HPCI system components on several occasions during the inspection period:

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pump suction from CST

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lube oil cooling supply

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steam supply isolation valves

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turbine exhaust vacuum breakers

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overspeed trip logic No unacceptable conditions were note .5 Quality Group Findings

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On August 31, the Unit 2 NRC resident inspector iaentified numerous wiring errors in the Unit 2 Power Generation Control Complex (PGCC)

panels. Unit 2 PECO QC was made aware of the' finding and began investigating to determine the extent and cause of the incorrect wiring. Unit 2 PEC0 QA subsequently informed the Unit 1 Operations

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Quality Control department, however the initial actions taken'did not appear to be adequate to fully identify the extent-of the problem on Unit 1 and the plant operations department management was not appraised of the problem until' prompted by the Unit 1 Senior Resident Inspector. A subsequent inspection of a sample of Unit 1 PGCC electrical panels identified numerous deficiencies. The two types of discrepancies identified were :

1) inactive electrical leads which were not properly insulated and secured in_the panel, and 2) vendor leads which are incorrectly identifie The licensee field engineering group is reviewing the leads and, to-date, has found that the leads were inactive in accordance with an approved plant modification. However, the inactive leads should have had the lugs cut off, heat shrink insulation installed, and should have been secured in the wire bundle. All of the PGCC panels are to be inspected for this type of deficiency and correcte A Plant Operations Review Committee (PORC) was convened on December 8 to review'the results of the inspection and the potential impact of the discrepancies on the safe operation of Unit 1. The PORC determined that based on the satisfactory completion of blue tag, preoperational, and surveillance testing and the fact that the electrical panel inspection did not confirm any actual miswiring, continued operation of Unit I was warranted and no unsafe condition existed. PORC did request development of a plan by field engineering for final resolution of the problem of mislabeled vendor l leads. The inspectors will follow the results of the licensee's revie .0 Onsite Followup of Events The inspector performed onsite followup of the following events that occurred during the inspection period. The events were evaluated for I proper notification of the NRC, reactor safety significance, licensee l efforts to identify cause and propose effective corrective action, and verification of proper system design response.

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!b 4 .' 1 Secondary Containment Isolations An isolation of the reactor enclosure-occurred on~ November 6, followed by expected initiation of the standby gas treatment system (SGTS). The cause was a loss of secondary containment differential

, pressure. This was due to misalignment of air supply isolation valves because incorrect op> .lonal aids were attached to the valves. A similar problem occurred on October 24 and, to avofd recurrence, the licensee applied operator aids (notes) to the valves. The notes were attached to the wrong-isolation valves, such that operators incorrectly aligned the air supply system. The systems were properly reset and the operator af ds were correcte Another isolation of the reactor enclosure occurred on November 14 followed by the expected initiation of the SGTS and reactor enclosure recirculation (RERS) systems. The cause was a loss of differential pressure when the operating alignment of the reactor enclosure exhaust fans was changed from 'B' and 'C' fans operating to 'A' and 'C' fans operating. Due to system performance problems, the 'A' and 'C' fan combination is currently not able to maintain the required differential pressure. The SGTS and RERS functioned as designed, the isolation was reset, and normal ventilation was restore A third set of reactor enclosure isolations occurred twice on November 21 due to a low differential pressure signal. In both cases, the low pressure was due to ventilation supply and exhaust fan trips on low supply air temperature. The low temperature was caused by initiation of a turbine enclosure supply fan which resulted in reduced stearn flow to the supply fan heating coil Turbine enclosure heating coil steam flow was abnormally high at the first isolation due to both the temperature control valve and its bypass valve being open when the fan was restarted, thus starving

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the reactor enclosure heating coil. Low air temperature in the second isolation was due to an auxiliary boiler tri In both cases, all systems started as designe The inspectors confirmed proper system response and appropriate ENS notification in all above isolation .2 Feedwater Level Transient A reactor water level transient occurred on November 19 due to a loss of one feedwater pump and a failure c ' a master level controller, causing the other two feedwater pumps to increase spee Reactor water level increased to +53 inches (one inch below the high turbine trip setting). A licensed operator quickly recognized the event and took~ manual control of the remaining pumps, and the resulting decrease in level was limited to +17 inches (five inches

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above the low level scram set. point). Reactor' power decreased from 85% to 44%, due in part to a recirculation pump run back to 28%:

flo The cause of the level transient was an error by a nonlicensed operator who, when applying a block to a non-Class IE' auxiliary boiler circuit, had his hand slip which opened a breaker feeding power to feedwater and recirculation pump control circuits. In addition to the loss of master feedwater controls and recirculation flow inputs, certain nonsafety-related alarm circuits and indications were also lost. Normal reactor vessel level was stabilized within minutes, the breaker was reclosed, and power ascension was commenced approximately One hour later. Reactor power was returned to 85% the same day. The inspector confirmed proper system responses, operator adherence to procedures, and management overview of recovery activitie .3 Security Computer Outage

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The Unit 1 security computer failed on December 6 due to a secondary disc drive malfunction. Compensatory coverage of vital areas was achieved within 10 minutes for all but one room. A designated force member arrived at the rear corridor door of a room in the control enclosure with the wrong key. Upon realizing that the key was incorrect, the guard returned to the key issuance area, obtained a correct key, but arrived back at the door in question approximately 12 ninutes after the computer failure. Sweeps of all vital areas were completed, vital key inventories were confirmed, the security computer was returned to service and the NRC was appropriately notified via the EN The computer failure also resulted in a violation of technical l specification firewatch compensatory requirements. The inability of the normal firewatch person to gain access to an area (following the computer failure) resulted in exceeding the required hourly time interval by 17 minutes in the area.

! When the firewatch could not gain access to the area, security was contacted and dispatched a guard to open the door. However, the

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guard had the incorrect key which resulted in exceeding the hourly

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periodic key core changeout which was recently accomplished. Key l numbers are also rotated along with lock cores which contributed to l the selection of incorrect key The inspectors determined that the l' security force supervisor assigning keys failed to use procedures

! which have been properly updated and, instead, provided keys for the L compensatory responders from memory. The inspectors will follow the l

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licensee's subsequent description-of the above events, including corrective measures proposed, in the required reports to be submitted to the NR .0 Licensee Reports 5 .1 ~ In-Office Review of Licensee Event Report-The inspector. reviewed Unit 1 LERs submitted to the NRC Region I office to verify that details of the event were clearly reported, including the accuracy of the description of the cause and the adequacy of the corrective action. Where multiple causes are suspected, or may be different than reported in the LER, this is indicated below. The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted on-site followup. The following LERs were reviewed:

LER Number and Date Subject Root Cause 87-53 Incomplete Rod Worth Deficient Procedure 10/26/87 minimizer (RWM)

surveillance test l .87-54 Late scram discharge Incorrect test date 10/28/87 volume surveillance scheduled due to personnel l

l test error 87-55 . Appendix R License Inadequate design review 11/18/87 Condition violation

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b 87-56 Secondary containment Auxiliary boiler failure 11/16/87 isolation and initia- (dirty torch tip), loss of tion of SGTS and RERS auxiliary heating steam, on low reactor and supply fan trip enclosure pressure 87-57 Control room isolation Inadequate instruction of 11/16/87 and Control Room I&C technicians concerning Emergency Fresh Air radiation monitor bypass System (CREFAS) switcF initiation during troubleshooting 87-58 Secondary containment Auxiliary boiler trip on 11/19/87 isolation and SGTS/RERS high steam flow (cause initiation or, low unknown), and loss of reactor enclosure auxiliary heating steam to pressure supply fans / dampers

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87-59 Secondary containment Inadequate block applied to 12/2/F7 isolation and SGTS/RERS air compressor, leaking initiation on low check valve, and loose reactor enclosure damper air valve fittings pressure 87-60 Secondary containment Incorrect instrument air 11/25/87 isolation and SGTS/RERS valve closed due to initiation on low personnel error and reactor enclosure mislabelled valve pressure LER Nos. 87-56 through 60 were previously addressed in Detail 4 of Inspection Report 50-352/87-2 LER Nos. 87-53, 54, 59 and 60 are addressed in Detail 5.2 of this repor LER No. 87-55 is addressed in Inspection Report No. 50-352/87-2 .2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup, the inspector verified that the reporting requirements of 10 CFR 50.73 and Technical Specifications had been met, that appropriate corrective action had been taken, that the event was appropriately reviewed by the licensee, and that continued operation of facility was conducted in accordance with Technical Specification limit . LER No. 87-53; Incomplete RkN Surveillance During a reduction in reactor power on September 26, the rod worth minimizer (RWM) began automatically enforcing control rod motion at 25% power, as designed. Within eight minutes after reaching that point, surveillance test (ST)-6-073-320 was performed to verify proper RWM indication of a control rod selection erro Approximately eight hours later, the individual assigned to review completed test procedures identified a portion of the RWM test involving the Select Error light which had not been performed because of a missing page in the procedure. The verification of proper RWM indication, required within one hour following automatic initiation of the RWM, was a licensee-identified violation of technical specifications (50-352/87-28-02).

The inspector concluded that the violation met the criteria of the NRC's Enforcement Policy to self-identified findings, and that no Notice of Violation would be issued, because the mistake has not been a recurrent problem and the minimal significance with

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respect to reactor safet The mistake existed for only eight hours and was promptly detected by the.next shif Subsequent operability of the RhN select error light was confirmed. Furthermore, reactor power at the time of the discovery of the in' complete test was 22%, and recent GE evaluations have concluded that a cropped rod accident (the design basis for the-RhN) is only significant at_

power levels below 10-15% powe Most significantly, the licensee's corrective action was extensive and should represent an improvement in the conduct of surveillance testing. Effective October 19, the licensee relieved the control room shift clerk from the responsibility of providing copies of test procedures to be conducted by operating staff. Instead, a more controlled and consistent method of updating the startup and shutdown. procedure binders (used to obtain test procedures during those fast turnaround situations) will be assumed by the licensee's Nuclear Records Management group. The controlled copy binders will be maintained in the control room, and responsibility for completeness and

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update (including periodic audits) will be with that group. This action represents the culmination of an evolution of measures which will assure that, during rapid plant operational condition changes, important surveillance testing which can only be performed at those times is completed satisfactoril . LER No. 87-54; Late SDV Surveillance Test

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The inspector assessed an error made by an I&C test coordinator

_resulting in a functional test of a high scram discharge volume (SOV) water level switch being overdue by 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />. The switch enables a control rod block, and was later successfully teste All other similar SDV switches were available and operable, Reactor power was at 12% at the time that the surveillance lapsed, and no control rod moves were being performed, nor were any high level alarms presen The inspector concluded that no citation would be issued for this licensee-identified violation (50-352/87-28-03) since it was not safety significant and not a recurrent proble Appropriate reporting and corrective actions were accomplishe It is a notably consistent trait for licensee first-line supervision to review completed test procedures or impending test schedules and, as a result, identify errors which are then promptly corrected. In this particular case, planning for weekend work loads identified (two days ahead of the incorrect schedule) that the wrong due date had been assigned for ST-2-047-614-1. Sufficient staffing and supervision of test personnel, and a well-managed test program, enabled the

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discovery of the overdue test. No other similar incorrect schedule entries were found, and the I&C group created a special tracking list for tests close to expiration of their surveillance interva The' inspector had no further concern . LER Nos. 87-59 and 60; Secondary Containment Isolations The inspector noted that a thorough root cause analysis had been presented for the reactor enclosure isolations described in the subject LER's. The events were caused by a lack of a complete and accurate identification and tagging system for instrument air tubing and block valves, and a failure to assess the consequences of taking an air compressor out of servic Both LER's involved substantial interaction and discussion between site operating staff and corporate licensing engineer As a result, comprehensive root cause determinations were made that enabled what appear to be corrective measures that will prevent additional instrument air problems and better correlate air supplies, loads and isolation valves. LER 87-60 describes modification number 5561 which is currently in progress to:

(a) walkdown all instrument air lines; (b) revise P&ID's appropriately; (c) add additional or delete unnecessary instrument root / block valves; and (d) create unique valve tag number LER 87-59 utilized a simplified sketch to describe the event. Both LER's detailed previous similar occurrences and, where necessary, correlated lessons learned. Both LER's were concluded by the inspector to be of high qualit .3 Review of Periodic and Special Reports Periodic or special reports submitted by the licensee were reviewed by the inspector. The reports were reviewed for the required information, that results and/or supporting information were consistent with design predictions and performance specifications, and whether any information in the report should be classified as an abnormal occurrenc The following reports were reviewed:

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Revision to August and September 1987 Monthly Operating Reports, dated November 5

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Monthly operating reports for October and November 1987

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PEF.0 letter to NRC (Fogarty to Russell) dated November 30, 1987; Summary Reports for ISI and ASME Repairs

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PECO letter to NRC (Gallagher to Gallo) dated December 9, 1987; Response to Inspection 50-352/87-25 violation, MRF closeout

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PEC0 letter to'NRC (Gallagher'to Gallo) dated November 9, 1987; Response to Inspection.50-352/87-19 violation, drawing control

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PEC0 letter to NRC (Kemper to Butler) dated' November 5, 1987; Additional information on LPCI license Amendment-

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PECO letter to NRC (Alden to Russell) dated November 16, CILRT Report The. inspector had no questions about_the report .0 Surveillance Testing 6.1 Test Observation The inspector observed the performance of and/or reviewed the results of the following tests:

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ST-6-107-590; Daily Surveillance Log

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'ST-3-048-230-1; Standby Liquid Control Functional

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ST-6-047-750-1; CRD Accumulator Weekly Pressure Check

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ST-2-042-607-1; Monthly ECCS and Reactor level Calibration

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ST-6-092-311 and 312-1; Monthly D-11 and D-12 Diesel Run

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ST-2-047-613-1; RPS Scram Discharge Volume Channel B High Level

-~ ST-2-050-601-1; Divisions 1 and 3, ECCS/ ADS Timer Calibration Pressure Test

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ST-8-092-321; 4 kV Emergency Safeguard Bus Undervoltage Check

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Li-6-011-206-2; ESW Quarterly Valve Test

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ST-6-057-200-1; Containment Atmosphere Control Valve Test

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ST-6-049-230-1; RCIC Quarterly Pump Test The tests were observed to determine that surveillance procedures conformed to Technical Specification requ rements; testing was being performed in accordance with Administrative Procedures A-43 and 47; proper administrative controls and tagouts were obtained prior to testing; testing was performed by qualified personnel in accordance with approved procedures and calibrated instrumentation; test data and results were accurate and within Technical Specification limits; and equipment was properly returned to service following testin No unacceptable conditions were note _ _ _ _ .

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7.0 Maintenance The inspector observed selected maintenance activities on safety related equipment to ascertain-that: the work was conducted in accordanceLwith Administrative Procedures A-25, 26 and.27 using approved work instructions or procedures; proper equipment permits and tagging were applied; craft performing the work'were appropriately qualified and supported; and return-to-service of equipment included adequate post-maintenance testing and operational verificatio .1 Work Observation Portions of the following work activities were observed or reviewed:

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MRF # 8781774; HPCI Booster Pump 011 Change

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MRF # 8708334; Division 3 Battery Charger Circuit Board Repair

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MRF # 8707675; MOVATS Testing on HPCI Valve HV-55-1F008 No unacceptable conditions were note .2 HPCI Overspeed Trip Failure On December 7, the high pressure coolant injection (HPCI) pump was taken out of service for preventive maintenance. The booster pump bearing oil was replaced under maintenance request form (MRF)

8781774 and in accordance with preventive maintenance procedure PMQ-500-006. Oil samples were obtained for routine analysi The inspector verified that administrative approval had been obtained and that an appropriate system tag-ou; was in plac During observation of the work the inspector noted that the licensee quality control (QC) inspector was present to observe those portions of the procedure identified as QC hold points. The QC inspector was knowledgeable of his responsibilities and the inspection requirements for this activit Following the completion of the work the pump was run as part of the retest and to complete the routine surveillance test requirement During this run, overspeed trip problems were encountered at an actual turbine speed below the overspeed trip setpoint. This problem does not appear to be related to the maintenance activity and a subsequent pump run was satisfactory with no apparent cause for the overspeed trip mechanism malfunction identified. The licensee suspects the spurious trips may have been caused by dirt partially blocking one of the trip mechanism's hydraulic ports, and was subsequently flushed from the port. An oil sample is planned to be take The inspector will follow the licensee's investigatio _ _ _ _ _ _ _ . _ _ _ .__ _ __ _ _ _ _ _ _ _ _ _ . _ _ _ _ - _ _ _

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8.0 Assurance of Quality 8.1 Worker Performance During Maintenanc An instance of good job planning and control was noted during repair of the Division 3 battery charger on December 4 as observed and noted in Detail 7.1. Engineering support was evident by the presence of maintenance staff and field engineering personnel. Full QC coverage of the job was performed and the assigned inspector was knowledgable of work instructions, procedural requirements and battery design. The craft assigned to the repair were two first-class mechanics from the licensee's specialized battery maintenance group who, when observed and questioned, appeared well qualified and cognizant of battery operation and vender recommendation The licensee obviously placed a high priority upon the repair of the battery charger, in part because of a general recognition by all involved parties of entry into an eight-hour technical specification action statement. However, the priority of the job as reflected by worker performance was also created by station management's cognizance of the risk importance of the batteries, particularly for station blackout concern .2 Management Involvement in Ooerations Station management and shift supervision were observed to be involved in the critique and analysis of the fire suppression valve blocking error addressed in Detail 3.2.1, Meetings and discussions among shift superintendents and operations management were held and, as part of corrective action for the violation, a videotape was being developed to address Unit 1 administrative controls as they apply to risk reduction in routine plant operating activities. The videotape.will involve 15 operators performing in short skits associated with fundamental duties such as fire program and equipment control concerns, stressing the themes of attention to detail, thought before action, and involvement of supervisio The licensee also convened a special PORC meeting to review 20 recent personnel error events and correlate these with nine separate potential causes involving concerns with communications, shift experience and procedure deficiencies. The matrix developed by the PORC identified several general areas of weakness in the conduct of operations which were being addressed by station management as distinct PORC commitments. The inspector concluded that station management is continuing to recognize and resolve important safety problems and, as evidenced by the above, propose unique corrective actions which have general support among the operating staf .. .

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8.3. Quality Findings Presentation

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An example was noted where a number of Unit 2 panel wiring errors were found by a recent NRC inspection (Report 50-353/87-13) in August 1987 but were not aggressively pursued'for potential impact upon Unit 1 desig The Unit 2 errors were documented as licensee QC findings for Unit 2 construction / design. However, the relevance to Unit 1 panels was inadequately evaluated by operations QA or QC groups and, af ter over two months time, only a very small sample of Unit I wiring terminations were inspected. Moreover, the number of errors found were large enough to warrant an expanded sample but none was performed, iritially. The errors were not described or communicated to Unit 1 station management until such time that NRC concerns were raised. As discussed in Detail 3.5, an expanded sample was then performed, the errors were evalrated and characterized by the PORC, and appropriate information was developed to enable a decision on the immediate safety significance of the problem for continued operation. Better communication among the various licensee quality groups is needed, as well as development of a sensitivity for immediate operational concerns and presentation of those findings to operational staf .0 Scram Discharge Volume Capability (Multiplant Acticn Item B-58)

In 1980 during a routine shutdown at another BWR facility, about 40% of the control rods failed to insert on a manual scram signa Followup of this event revealed a number of deficiencies with the scram discharge volume (SDV) headers. Multiplant Action (MPA) Item B-58 "Scram Discharge Volume Capability" was assigned by the NRC to track this issue. An NRC generic study, "BWR Scram Discharge System Safety Evaluation" dated December 1, 1980 provided criteria for correcting identified deficiencies in the SDV syste NUREG-0991, the Limerick SER dated August 1983, states that NRC has reviewed the extent of conformance of the SDV design with the criteria of the generic safety evaluation. The Limerick design provides two separate SDV headers, with an integral instrument volume (IV) at the end of each header, thus providing close hydraulic coupling. Each IV has redundant i and diverse level instruments (float sensing and pressure sensing) for

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the scram function attached directly to the I Vent and drain lines are separated and contain redundant vent and drain valves equipped with redundant solenoid pilot values. High point vents are provided. The NRC

, staff concluded the design of the Limerick SDV fully met the requirements j of the NRC generic report and was acceptabl NRC Temporary Instruction (TI) 2515/90 provides inspection guidance to ensure the SDV meets ge' requirements, and lists 11 criteria along with actions to be take ;dit compliance with the requirements. The j following sections list c i criterion and discuss its dispositio .

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9.1 Scram Discharge Header Size (Criterion 1)

Criterion 1 specifies that SDV headers shall be sized in accordance with GE-0ER-54 and shall be hydraulically coupled to the instrumented volumes in a manner to permit operability of the scram level instrumentation befcre loss of system functio GE-0ER-54 states the SDV header should be sized for a minimum of 3.34 gallons par control rod drive. The Limerick design specification provides for 3.34 gallons per control rod drive. In Inspection Report 352/87-13 the inspector evaluated the results of preoperational test P55.1 conducted in March 1984 to confirm the SDV as being 634.8 gallons, which is mere than the minimum required 618 gallons. The SDV capacity does not include volumes associated with vent and drain lines or the instrument volumes and connecting pip The SDV header, an eight inch diameter pipe, is connected to the instrument volume, a 10 inch diameter pipe with a short eight inch diameter line. SDV pipe and connections to the IV slope downward to ensure draining. There are no reductions in pipe size from the HCUs to the SDV-IV. Therefore hydraulic coupling is ensure As the IV starts to fill, level instruments trigger an alarm or scram before tne SDV header begins to fill. This ensures the scram

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header is able to accept the water. The inspector examined the SDV piping and connections, and no problems were noted. SDV headers appear to be adquately sized and hydraulically coupled to the I .2 Automatic Scram on High SDV Level (Criterion 2)

Criterion 2 states that level instrumentation shall be provided for automatic scram initiation while sufficient volume exists in the SD In Inspection Report 352/84-01 the inspector verified the existence of two diverse means of water level indication for each IV that interfaces with the reactor protection system to cause a high IV water level scram. This scram will be initiated while sufficient volume exists in the SDV to accept the discharrged wate .3 Instrument Taps not on Connected Piping (Criterion 3)

Criterion 3 states that instrumentation taps shall be provided on the vertical IV pipe, and not on the connected pipin FSAR question 410.20 states that all instrumentation taps for the IV are located on the vertical IV and not on connecting pip The inspector visually verified this to be tru .

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9.4 Detection of Water in the IV (Criterion 4)

.In accordance with~ Criterion 4, scram-instr'.' mentation shall be capable of detecting water accumulation in the IV assuming a single active failure in the instrumentation system or the plugging of an instrument lin In Inspection Reports 352/84-01 and 352/87-13 the inspector verified the existence of redundant and diverse means of detecting water level for each IV to cause a high level scram. Two differential pressure transmitters and two float switches are employed in each IV scram circuit. The two IVs are hydraulically coupled via a common drain lin .The inspector reviewed the FSAR, technical specifications and plant drawings to confirm an automatic scram function exists for high IV water level. The instrumentation is diverse and satisfies the single failure criterio If a single failure should occur, there is sufficient redundancy to ensure that the instruments would respond properl .5 Vent and Drain Valves System Interf aces (Criterion 5)

Vent and drain functions shall not be adversely affected by other system interfaces. The objective of Criterion 5 is to preclude water backup in the scram IV, which could cause a spurious scra The inspector reviewed the FSAR and drawings M-47, M-53 and M-6 The SDV drain line discharges into the equipment drain collection tank (EDCT). The SDV vent line discharges to dirty radwaste and is protected by a vacuum breaker (PSV-120). Redundant isolation valves on the vent and drain lines are normally open and would not prevent draining these lines in the non-scrammed condition. The inspector noted that FSAR question 410.20 erroneously states the vent lines discharge to the EDCT. This observation was discussed with licensee I representatives who indicated FSAR changes would be made.

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The two-inch drain line from the SDV-IV connects to the reactor well

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seal rupture drain line, an eight-inch line which discharges into l the 25,000 gallon capacity EDCT. The tank has an overflow line to dirty radwaste. A rupture of both refueling cavity inflatable seals could cause the EOCT to overflow and flood the radwaste building floo The water should not backup into the IV because of elevation differences between the IV, the drain tank, and the radwaste

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building floo Neither the vent nor drain function would be adversely affected by other system interfaces. Based upon an examination of visible portions of the vent and drain systems, review of appropriate drawings, and documentation, no unacceptable condition were note . . . . __,._,. . _ _ _ . . _ .

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, 9.6 Vent Drain Valves Close on Loss of Air (Criterion 6]

Criterion- 6 ~ addresses closure of the power-operated vent and' drain

valves under loss of air and/or electric power. Valve position-indication shall be provided in the control roo . The inspector reviewed. drawing M-47 and the appropriate FSAR discriptions and examined the vent and drain valves. The vents and -

drains are air operated air-to-open and spring-to-clo e valves which fail closed under loss of air and/or electric power. Valve position indication is provided in the control room, in accorda,ce with Criterion .7 Operator Aid (Criterion 7)-

Instrumentation shall be provided by Criterion 7 to aid the operator in the detection of water accumulation in the IV's before scram initiation' .

The inspector reviewed plant drawings and visually verified that an

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alarm exists in the control room. Level switches on each IV sound an alarm in the control room when the level reaches five gallon The annunciator response card instructs the operator to enter operational transient procedure OT-105, which requires verification ,

that all vent and drain valves are open. A controlled shutdown is

. initiated if the SOV-IV cannot be drained. Lights in the control .

room indicate valve position; Based upon this inspection it is concluded that instrumentation and procedures are provided to aid the operators in detection of water ,

in the IV before scram initiatio .8 Active Failure in Vent and Drain Line (Criterion 8)

Vent and drain line valves shall be provided to contain the scram discharge water with a single active failure and to minimize operational exposure, in accordance with Criterion 8.

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Redundant SDV vent and drain valves are provided to ensure that no '

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single active failure can result in an uncontrolled loss of reactor

, coolan Redundant solenoid-operated pilot valves control the vent and drain valves, The valves fail in the closed positio The inspector verified the valves were as described in the FSAR by visual observation and review of drawings. Procedure GP-11, Reactor Protection System-Scram Reset, requires a radiation survey of the f i SOV prior to releasing the fluid inventory if fuel damage is  !

suspected. The licensee indicated the SDV is routinely monitored af ter all scrams. Radiation surveys of the SDV area are performed weekly, t

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9.9 Periodic Testing of Vent and Drain Valves (Criterion 9)

In accordance with Criterion 9, vent and drain valves shall be periodically teste Technical Specification 4.1.3.1.1 requires periodic testing of the v:at and drain valves. Demonstration of operability verifies each valve to be open at least once per 31 days, and operating each valve through at least one complete cycle of full travel every 92 day Technical Specification Table 3.6.3-1 indicates maximum closing times as:

F010 inner vent 25 seconds F011 inner drain 25 seconds F180 outer vent 30 seconds F181 outer drain 30 seconds In Inspection Report 352/84-01, the inspector verified the existence of testing procedures to show the operability of the SDV vent and drain valves. The procedure is ST6-047-200-1 "SDV Valve Exercise Test" performed quarterly. The maximum closing time is measured in the surveillance tes '

9.10 Periodic Testing of Level Detection Instrumentation (Criterion 10)

Level detection instrumentation and verifying level detection instrumentation shall be periodically tested in plac Technical Specificaiton 4.1.3.1.4 requires that SOV level instruments be periodically tested in place. A channel functional test of the rod block and scram level instruments is required every 31 days. Technical Specification Table 4.3.1.1-1 requires the scram instruments to be calibrated each 18 months. The following surveillance tests satisfy Criterion 10:

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Test Level Instrument Frequency ST-2-047-407 thru 410 LT-47-IN012A thru 0; 18 LISH-47-IN601A thru D 18 ST-2-047-612-1 LSH-47-IN013A 1 ST-2-047-602-1 LSH-47-IN013C 1 ST-2-047-603-1 LSH-47-IN013D 1 ST-2-047-613-1 LSH-47-IN0138 1 ST-2-047-608 thru 611 LISH-47-IN601A thru D 1 ST-2-047-614 and 615 LSH-47-IN013E 1 The inspector concluded that appropriate surveillance tests exist that incorporate restoration steps including independent verifications of statu . . . . ... - --- .-

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9.11 Periodic Testing Operability-of the Entire System (Criterion _11.)

The operability of the entire system-as an_ integrated whole'shall be demonstrated periodically and during'each operating cycle by-demonstrating scram instrument response and valve function at pressure and temperature at approximately 50% control rod densit Technical Specification 4.1.3.1.4.a requires the system to be demonstrated. operable when control rods are scram tested from a normal control rod configuration of'less' than or equal to 50% rod 3 density at least once per 18 months. Procedure ST-3-047-320-1, "SOV :

Operability on Scram" implements this: requirement. The inspector ,

reviewed ST-3-047-320-1 performed on 5/2/86, 1/27/87 and 5/18/8 No unsatisfactory conditions were note L 10.0 Exit Meeting The NRC resident inspectors discussed the issues in this report throughout the inspection period, and summarized the findings at an exit meeting held with the Station Manager on December 7, 1987'and again with the Superintendants of Operations and Services on December 10, 198 At ;

the meeting, the licensee's representatives indicated that the items-discussed,in this report did not involve proprietary information. No .

written inspection material was provided to licensee representatives during the inspection period.

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NRC Form 766 U. S. NUCLEAR REGULATORY COMMISSION Principal Inspecto Kelly, Gene Reviewer: J. Linvill INSPECTOR'S REPORT Office of Inspection and Enforcement inspector Transaction h Docket #/ Inspection #/ Seq #

h Type: h E. Kelly h h L. Scholl h* I-Insert h 05000352 87-26 A h M-Modify h h D-Delete h Licensee / Vendor: h R-Replace h Philadelphia Electric C h Atta: Mr. 1 Gallagher V. P Nuclear Servicts 2301 Market Street Philadelphia, PA 19101 Period of Inspection: h Inst,ection Performcd By: Organization Code of Reg.:

From To h 1-Regional Office Staff h Region Division Branch ha 2-Resident Inspector h I B B 11/01/87 12/10/87 4 3-Performance Appr. Team h h -Other h

Regional Action: Type of Activity Londucted (* one only):

1 - NRC Form 591 h* 02-Safety 07-Special 12-Shipment / Export

• 2 - Regional h 03-Incident 08-Vendor 13-Import Office Letter 04-Enforcement 09-Mat. Acc Inquiry 4 05-Mgnt. Audit 10-Plant Se Investigation 06-Mgnt. Visit 11-Invent. Ve h Total No. of h Enforcement h Report itolations and h Confer >nce h Contains h Deviations: h Held: h 2.790 h h Inforaation:

h 01 h h Inspection Findings: h Letter or Report Transmittal i

A B C D h Date l - Clear h

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X - Violation h NRC Form 591 or Region l - Daviation h Letter Issued:

- Vio ation & Deviation h Report Sent to HQ for h Action:

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INSPECTOR'S REPORT (Continuation)

Docket No. 05000352 Report No. 87-28 Seq. A Module Number 71707 Violation Severity IV As a result of an inspection conducted on November 1 - December 10, 1987, and in tccordance with the General Statement of Policy and Procedure for NRC Enforcement Actions, 10 CFR Part 2, Aopendix C (1987), the following violation was identified:

Technical Specification 6.8.1 requires that plant procedures be implemented, including those procedures recommended in Appendix A of 4 Regulatory Guide 1.33, Revision 2, for administrative control of plant equipmen Administritive Drocedures A-8 and A-41 provide measures for the control of locked valves and the removal from service of equipment required to be operable by the Technical Specifications, respectivel Step 5.1 of both procedures A-8 and A-41 requires shift supervision permission to change locked valve position or the release of equipment fer maintenanc Contrary to the above, on November 16, 1987, fire suppression water isolation valves numbered HV-022-1106 and 0058 were unlocked and closed from 1:00 am to 5:15 am without shift supervision permission. This resulted in the isolation and inoperability of 17 fire hose stations and safety-related ventilation system filters without the establishment of compensatory firewatches and substitute fire hose water source This is a Severity Level IV Violation. (Suppl (ment I)

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NRC Form 766 - Continued MODULE INFORMATION Record / Direct Percentage Status Module Module No. Insp. Hours Complete Followup

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B 530703 10 B 571707 80 100 B 25590 25 100 C B 361726 20 100 B 562703 15 100 8 571710 9- 100 8 590712 4 B 592700 5 B 590713 2 B 593702 4 B 571881 5 100 B 571709 5 100 B 525026 10 20

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NRC Form 6 Rev. Dec. 86 0VTSTANDING ITEMS FILE SINGLE DOCKET ENTRY FORM Docket Number: 50-352 Originator: Kelly, Gene Reviewing Supervisdrg 4dr lle, James i M u1

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Report Hours: 1. Operations _ 83 7. Out s 2. Rad-Con _8 8. Training __0 3. Maintenance _ 18 9. Licensing _0 4. Surveillance -23 10. QA 14 5, Emerg. Pre _4 11. Other(Engineering [35 6. Sec/Safegrd _9 12. Fire Protection /

Housekeeping item Num, hType hSALP Area 01 Area hAction Oue hUpdt/C1sout Rpt40 ate 0/M/Cis 87-28-01 NC4 Operations PSC 04/05/87 12/10/87 0 Originator: Kelly Modifier / Closer:

Descriptive Title: FAILURE TO FOLLOW ADMINISTRATIVE PROCEDURE A-8 and A-41 Item Num. Type hSALP Area h0I Area hAction Due hUpdt/Clsout Rpth0 ate 0/M/Cls 87-28-02 NV4 PSC 87-28C 12/10/87 0 C Originator: Kelly Modifier / Closer:

Descriptive Title:

Item Num, hType hSALP Area liOI Area hAction Due hUpdt/Ciscut RpthDate 0/M/Cis 87-28-03 NV4 PSC 87-28C 12/10/87 0 C Originator: Kelly Modifier / Closer:

Descriptive Title:

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