IR 05000354/1986030

Insp Rept 50-354/86-30 on 860610-0714.Violations Noted: Ineffective Program for Tracking RCIC Sys Operability & Failure to Take Timely Corrective Actions for QA Identified Discrepancies

ML20204H777
Person / Time
Site:	Hope Creek
Issue date:	07/29/1986
From:	Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20204H755	List: IR 05000354/1986030 ML20204H750 ML20204H756
References
50-354-86-30, NUDOCS 8608080194
Download: ML20204H777 (19)

Text

._ _ .

.

. .

V. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /86-30 Docket 50-354 License NPF-50 Licensee: Public Service Electric and Gas Company Facility: Hope Creek Generating Station

.

Conducted: June 10 - July 14, 1986 Inspectors: R. W. Borchardt, Senior Resident Inspector D.K.Allsopp,Res{dentInspector R. J. Summeys, Project Engineer Approved: s A

L.Norhop,~ Chief,ProjectsSection28 Date

Inspection Summary:

Inspection on June 10,1986 - July 14,1986 (Inspection Report Number

,

50-354/86-30)

Areas Inspected: Routine onsite resident inspection of the following areas:

followup on outstanding inspection items, operational safety verification, surveillance testing, maintenance activities, engineered safety feature (ESF)

system walkdown, preoperational/startup testing, licensee event report followup, evaluation of spurious ESF actuations, corrective action program, Electrical, Instrumentation and Control Systems Branch visit, NRC Commissioner's visit, and main steam isolation valve spring inspection. This inspection involved 353 hours0.00409 days <br />0.0981 hours <br />5.83664e-4 weeks <br />1.343165e-4 months <br /> by the resident and project inspector Results: A large percentage of inspection effort during this report period was directed towards the preparation for, and performance of initial criticality operations. These activities were generally well controlled and coordinated with a consistent emphasis on safety. Two violations were also identified during the report perio First, failure to have an effective program for tracking system operability resulted in a violation of Technical Specifications due to the loss of the auto-swap capability of the suction flow path for RCIC. Although this problem l was self identified, the violation was issued due to the significance of the l event.

,

l Second, failure to take timely corrective actions for Quality Assurance (QA)

i identified discrepancies has been cited as a violation of 10 CFR Appendix B.

.

8608080194 860731 PDR ADOCK 05Ng4

.

. . .

._

.. . . . - - - .-

- . _ .

i

.

. .

In the past, inspectors have identified discrepancies similar to those identified by QA and have allowed the internal corrective action program to resolve these problems. However, review of your corrective action program indicates that the organization as a whole is not always responding adequately to self identified deficiencies. A large percentage of individual department responses to QA action requests are submitted well past the response due dates with no extension requeste _ _ _ _ - _ _ _ _ _ _ _ _ _ - _

.

. .

DETAILS 1. Persons Contacted Within this report period, interviews and discussions were conducted with members of the licensee management and staff and various contractor per-sonnel as necessary to support inspection activit . Followup on Outstanding Inspection Items 2.1 Violations (Closed) Violation (86-20-01); Filtration, Recirculation and Venti-lation System Operabilit (See below)

(Closed) Violation (86-20-02); Standby Liquid Control System Sur-veillance Testin During initial fuel load activities the inspector identified two vio-lations which resulted from making the Filtration, Recirculation and Ventilation system (FRVS) inoperable and failing to perform required surveillance testing on the Standby Liquid Control system (SLC).

The licensee's response to these violations was provided to the NRC in a letter dated June 19, 1986. The control room console checklist (OP-AP.ZZ-107) and the Operation's Department Surveillance Log (OP-OL.ZZ-026) were revised in an effort to prevent recurrence of these violations. The inspector has no further questions at this time and will continue to review the licensee's compliance with Tech-nical Specifications on a routine basi .2 Inspector Follow Items (Closed) Inspector Follow Item (86-02-03); Planning and Scheduling Administrative Procedures. The inspector verified that the Plan and Scheduling Department administrative procedures have been written and approved. The following procedures were specifically reviewed:

-

PL-AP.ZZ-002(Q) Station Planning Department Organization

-

PL-AP.ZZ-101(Q) Unscheduled Outage Planning

-

PL-WP.ZZ-003(Q) Scheduling Input to PREMIS

-

PL-WP.ZZ-002(Q) Retest Package Preparation

-

PL-WP.ZZ-001(Q) Planning and Scheduling of Work Orders The inspector has no further question (Closed) Inspector Follow Item (86-20 01); Investigation of Spurious LOCA Signal During the time period between fuel load and initial

_. _ _ __

.

. .

criticality the licensee experienced a number of single channel Loss of Coolant Accident (LOCA) signals. Special Test Procedure 86-05-29-112-5-1 was performed to determine the cause of these spurious signals and the results of this procedure are discussed in paragraph 9 of this repor (Closed) Inspector Follow Item (85-53-01); Management Coordination and Awareness of ED0's Priorities (Closed) Inspector Follow Item (85-53-02); TSC Discussion of Emer-gency Power Requirements (Closed) Inspector Follow Item (85-53-03); Radio Communicator Use for Other Purposes (Closed) Inspector Follow Item (85-53-04); Confusion About Tagging Procedure use in Emergency (Closed) Inspector Follow Item (85-53-05); Rad Protection Personnel Tracking Difficulties (Closed) Inspector Follow Item (85-53-08); Handling of Iodine Sample by Environmental Team (Closed) Inspector Follow Item (85-53-10); E0F Functions Duplicated (Closed) Inspector Follow Item (85-53-11); Minimal Decision Making by Rad Safety Manager On October 28-30, 1985, an NRC inspection team observed the licensee's annual full scale emergency exercise (Delaware only). No significant deficiencies were identified; however, as a result of these observations, the items listed above were identified as areas which deserved the licensee's evaluation and possible corrective ac-tion. The next full scale emergency exercise will be observed by the inspector and the results of the October 1985 exercise will be re-viewed prior to its start. The inspector will then evaluate the licensee's corrective actions resulting from the October 1985 exer-cise. For administrative purposes the items listed above are closed, l however the inspector will review the October 1985 exercise results prior to the next full scale exercise and evaluate the licensee's corrective actions (86-30-01).

2.3 Unresolved Items (Closed) Unresolved Item (86-10-03); Retest of Acoustic Monitors.

i Each reactor pressure vessel safety relief valve (SRV) has an acous-tic monitor mounted on the discharge pipe to the torus which will give the operators indication of an open SRV. Because of problems identified during the preoperational test program this open item was written to verify that all acoustic monitors were installed and

__ _

. .  ;

operable prior to drywell closure and initial criticality. The in-spector reviewed completed work order 86-06-17-022-4 which verified operability. The inspector also conducted an independent tour of the drywell and found the acoustic monitors to be properly mounted. This item is close .4 Construction Deficiency Report (CDR)

(Closed) Construction Deficiency Report (86-00-03); Diesel Air Start System. The subject CDR identified inadequate venting of the diesel rack boost cylinder after start signal termination on Colt-Pielstick PC-2 engines. This causes the boost cylinder to fight the governor and creates a potential overspeed condition and resultant overspeed tri To correct this deficiency, the licensee has completed installation of Colt-Pielstick recommended alteration to positively vent the rack boost cylinder promptly after start signal termination. All complet-ed piping modifications have been leak tested. All diesel engines have subsequently passed surveillance testin The inspector reviewed the work packages, questioned the system engi-neer, and conducted an in plant walkdown of all diesel air start mod-ifications. No problems were identified. This item is close .5 IE Bulletins, Circulars, and Notices (Closed) IE Bulletin (86-8U-01); Minimum Flow Logic Problems that could Disable RHR Pumps. This bulletin concerns the potential loss of all RHR pumps due to a single failure of the minimum flow logi A minimum flow logic failure could cause all RHR minimum flow bypass valves to shut and result in all RHR pumps running dead headed with potential for pump damage in several minute The inspector reviewed the licensee's response, FSAR, RHR piping and instrument diagrams, and conducted an in plant inspection. The licensee's RHR system consists of four RHR pumps, each with its own minimum flow line, bypass valve, flow element, and flow transmitte These four RHR channels are physically, electrically, and logically independent. A single failure in any one RHR minimum flow path, including the bypass valve, will disable only that one RHR loo This item is close . Operational Safety Verification 3.1 Documents Reviewed

-

Selected Operator's Logs

-

Senior Shift Supervisor's Log

-

Jumper Log

-

Radioactive Waste Release Permits (liquid & gaseous)

__ __

.

. .

-

-

Selected Radiation Work Permits (RWP)

-

Selected Chemistry Logs

-

Selected Tagouts

-

Health Physics Watch Log 3.2 The inspectors periodically toured the plant during regular and backshift periods. These tours included the control room, Reactor, Auxiliary, Turbine and Service Water buildings, and the drywell (when access is possible). During the inspection activities, discursions were held with operators, technicians (HP & I&C), mechanics, super-visors, and plant management. The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, Tech-nical Specifications, and Station Procedure (1) On a daily basis, particular attention was directed to the fol-lowing areas:

-

Instrumentation and recorder traces for abnormalities;

-

Adherence to LCO's directly observable from the control room;

-

Proper control room shift manning and access control;

-

Verification of the status of control room annunciators that are in alarm;

-

Proper use of procedures;

-

Review of Logs to obtain plant conditions; and,

-

Verification of surveillance testing for timely completio (2) On a weekly basis, the inspectors confirmed the operability of selected ESF trains by:

-

Verifying that accessible valves in the flow path were in the correct positions;

-

Verifying that power supplies and breakers were in the cor-rect positions;

-

Visually inspecting major components for leakage, lubrica-

,

tion, vibration, cooling water supply, and general operat-l ing conditions; and,

-

Visually inspecting instrumentation, where possible, for l proper operabilit (3) On a biweekly basis, the inspectors:

l l

i L

.

. .

'

-

Verified the correct application of a tagout to a safety-related system;

-

Observed a shift turnover;

-

Reviewed the sampling program including the liquid and gas-eous effluents;

-

Verified that radiation protection controls were properly established;

-

Verified that the physical security plan was being implemented;

-

Reviewed licensee-identified problem areas; and,

-

Verified selected portions of containment isolation lineu .3 Inspector Comments / Findings:

The unit entered this report period in Mode 4 with the reactor shut-down, coolant temperature less than 200 degrees F, conducting sur-veillance in preparation for initial criticalit In the previous inspection report period on June 7, 1986, the "A" Standby Liquid Control (SLC) system inadvertently actuated for sev-enteen seconds. The SLC pump started, squib valve fired and reactor water cleanup system isolated coincident with the manual start of the

"A" emergency diesel generator. Boron was injected into the core spray system, but the SLC pump was stopped prior to boron injection to the reactor vessel. The core spray lines were flushed with reac-tor vessel water through the fired squib valve into disposal drum Extensive review and testing has not identified the cause. The licensee mailed the Bailey 862 Solid State Logic modules associated

, with SLC to Bailey for additional testing. The inspector will follow l the licensee's efforts to identify the cause of this even The licensee has committed to submit a supplemental LER if the cause is determined.

!

l Initial criticality was achieved at 11:18 p.m. on June 28, and was l followed by a full core shutdown margin demonstration and a source

'

range non-saturation demonstratio Region I inspectors provided 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> / day coverage of initial criticality activities and will have expanded coverage for selected activities throughout the low power test progra For additional information on initial criticality, re-fer to paragraph 7 of this repor At 1:12 p.m. on June 29, 1986, the reactor scrammed on high IRM flu The reactor was in a non-coincidence RPS logic mode at the time

, (shorting links removed). After having just completed the necessary

! tests to install the shorting links, the reactor was placed in a j sub-critical condition. Due to decreasing neutron counts, the opera-l tor was downranging IRMs. The operator was attempting to downrange IRM "B" and selected IRM "D". IRM "D" exceeded the RPS trip point and a reactor scram occurred. All rods inserted. A Region I based

.

. .

startup inspector observed ifcensee's actions. The licensee rein-stalled the shorting links, restarted the reactor and resumed the startup program testin At 4:51 p.m. on June 30, 1986, the licensee manually scrammed the reactor to repair the Reactor Manual Control System (RMCS). The RMCS had been inserting a continuous rod motion block for unknown reason The licensee and General Electric representatives diagnosed the prob-lem as a failed RMCS power supply. The licensee completed RMCS power supply replacement and unit went critical at 6:42 p.m. on July On July 3,1986, the plant experienced two separate emergency core cooling system (ECCS) actuations which a subsequent investigation revealed to be caused by the improper calibration of a reactor vessel level transmitter. The transmitter being calibrated (3682 B) was a post accident monitoring device that shares common instrumentation piping with the Loss of Coolant Accident (LOCA) level transmitter On two separate occasions, while returning the 3682 B transmitter to service, the I&C technician apparently operated the instrument isola-tion valves too quickly and caused a perturbation on the common sens-ing lines. This perturbation caused the "B" LOCA level transmitters to trip, resulting in the "B" core spray, "B" low pressure coolant injection system, and the "B" diesel generator to start. All systems operated properly and the plant operators secured the pumps and die-sel. The inspector attended the post event fact finding meeting at which it was determined that a number of factors contributed to the inadvertent actuation of the emergency core cooling systems and the

"B" diesel generato It was not recognized, that although the 3682 B transmitter was not a safety-related instrument nor was its calibration required by Technical Specification (TS), it does share common reference and variable legs with safety related ECCS instrument i

-

A generic calibration procedure was used by the I&C technician which allowed him to perform the calibration dry (transmitter drained) instead of having the transmitter full as would normal-l ly be desire (TS required calibrations use instrument specif-ic procedures.)

! -

Because the calibration was not being done to satisfy a TS re-

t quirement, the technician chosen for the job was not one of the specially trained surveillance test technician These "ST" technicians have received special instructions on the precau-tions of working on ECCS instrumentation.

( Nuclear System Engineering and Instrument and Controls conducted a I review of P&ID M-42 and identified approximately eleven additional 1 Non-Technical Specification instruments that share common sensing lines with ECCS instrumentation. All work was stopped on the

. - - .-- _- ..--- - . ~ . .

,

<

.

. .

'

identified instruments until specific procedures were written and

,

approved. Once a procedure was available, calibration activities I i

could commence by an appropriately qualified technicia At 1:28 p.m. on July 4,1986, the reactor scrammed during heatup for

,

power ascension testing. The scram occurred when an APRM channel "E" high upscale neutron trip was coupled with a half scram manually in-

, serted due to narrow range level perturbations. The shift carried out the scram procedure and the plant was placed in a shutdown condi-l tion. The APRM channel "E" high upscale neutron trip was attributed i to a failed LPRM which was subsequently bypassed. The reactor was

. taken critical at 12:26 a.m. on July At 6:30 p.m. on July 6, 1986, an alert was declared when tampering

.

'

was considered a possible cause for the initiation of the Diesel Gen-erator (DG) Building Fire Suppression System. An air operated water

deluge valve opened and the electric fire pump started, pressurizing the sprinkler system and fire hoses in the D/G are '

No water was l actually released since the fusible links remained intact. The fus-ible links are designed to activate under the high heat conditions of

, a fire. Subsequent investigation revealed that an area detector (heat sensor) malfunction caused the system initiation and that tam-pering was not the cause. The alert was terminated at 7:30 p.m. on

_ vuly 6.

e At 5:32 p.m. on July 7, 1986, the "A" control room ventilation intake l duct radiation monitor spiked upscale causing the "A" train of con-

! trol room-ventilation to isolate. The "B" train of control room ven-i tilation was in service and was not affected. All equipment l responded as expected, the "A" monitor was verified to be faulty and

,

was placed in the tripped condition in accordance with Technical

Specifications.

! At 2:22 p.m. on July 12, 1986, the licensee inserted a manual scram l when both "C" and "D" steam flow transmitters in main steam line "B"

sensed high steam flow and shut all MSIVs. HPCI and RCIC were not 1 available to bleed steam to control pressure as the combined HPCI and RCIC full ficw test valve to the condensate storage tank was tagged shut for maintenance. The high steam flow indication was attributed I

to transmitter drift. Both "C" and "D" transmitters were replaced j and the reactor taken critical at 10:27 p.m. on July 13 to continue s low power testing.

t At 9:49 a.m. on July 14, 1986, an erroneous level-1 and level-2 chan-nel "A" LOCA signal was received. At the end of the report period, the licensee had not yet identified the root cause. All systems responded as expected for the plant conditions (Mode 2, reactor power

.1%, temperature 360 degrees F, pressure 140 psig). The "A" LPCI and HPCI pumps started but were manually secured prior to water injection into the vessel. "A" CS pump injected approximately 6000 gallons into the reactor vessel. The inspector will review this event when

the LER is submitted.

l I

.

. .

On July 14, 1986, the licensee discovered RCIC was inoperable while attempting to perform the RCIC condensate storage tank (CST) suction auto-swap to suppression pool functional test. An investigation de-termined the CST level transmitters were disconnected on June 27, 1986, for a design change and were out of service since that tim The conditions for the RCIC LC0 include the capability of automati-cally taking a suction from the suppression pool and transferring the water to the reactor pressure vesse Technical Specification 3. also requires RCIC operable in operational condition 1, 2, and 3 with steam dome pressure greater than 150 psig. On July 9, 1986, at 1:50 a.m. while in operational condition 2, reactor pressJre was raised to 155 psig and remained greater than 150 psig until a reactor scram occurred at 2:22 a.m. on July 12, 198 Entry into such specified conditions shall not be made unless the conditions of the LC0 are met as required by Technical Specification 3. Prior to this incident the Control Room Action Statement Log was only utilized to track equipment required to be operable in the present mode. On June 27, RCIC was not entered in the Action Statement Log because RCIC was not required to be operable at the time the Design Change Package work order was approved by Operations to start wor As immediate corrective action, the licensee has instructed all SR0s -

to utilize the Action Statement Log to track equipment in all opera-ting modes. Although the licensee identified this problem and has implemented immediate correction action, the inspector informed the licensee that the lack of an effective program to track system oper-ability resulted in a violation of Technical Specifications (86-30-02). Surveillance Testing During this inspection period the inspector performed detailed technical procedure reviews, reviewed in progress surveillance testing as well as completed surveillance packages. The inspector also verified that the surveillances were performed in accordance with licensee approved proce-dures and NRC regulations. The inspector also verified that the instru-ments used were within calibration tolerances and that qualified technicians performed the surveillance The following surveillances were reviewed, with portions witnessed by the inspector:

-

IC-CC.SE-029, OP-ST.SE-004, SRM Channel Functional Test

-

OP-ST.BD-003, RCIC System Functional Test In addition, surveillance activities supporting initial criticality were also observed as discussed in paragraph 7 of this repor No violations were identified.

I

.

. .

~

11 Maintenance Activities During this inspection period the inspector observed selected maintenance activities on safety related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifi-cations, and appropriate industrial codes and standards. The following activities were reviewed:

Work Order Description 86-07-02-010-2 Troubleshooting / Repair of SLCS tank level transmitters 86-06-09-112-0 Repair of MSIV 86-06-09-125-1 Removal of hanger / interference No violations were identifie . Engineered Safety Feature (ESF) System Walkdown The inspectors verified the operability of the selected ESF systems by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match plant drawings and the as-built configura-tion. This ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumenta-tion is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriate. The control rod drive (CRD), core spray loop A, and the standby liquid control (SLC) system were inspecte During the walkdown of the CRD system the inspector observed inadequate channel separation between two back-up scram pilot electrical cables. The inspector informed QA of this condition and work order 86-07-03-017-5 was written. The inspector reviewed this work order and had no further question During the walkdown verification of the SLC system, a number of discrep-ancies were identified as follows:

-

Valve 1-BH-V024 was closed (normally locked-open)

-

Valves 1-BH-V006 and 7 did not have locking devices installed; and,

-

Valves 1-BH-V062, 63, 64 and 65 were not listed on the valve lineup procedure (OP-SO.BH-001(Q))

Valve 1-BH-V024 is a normally locked-open valve in the test tank supply line to the "A" SLC pum This test line is normally isolated by a locked-closed valve (1-BH-V053) at the discharge of the test tank. There-fore 1-BH-V024 is not in the normal suction flow path to the pump and would not have prevented system operation. The remaining discrepancies

._ _ _ - --

.

. .

-

also would not have prevented system operation, because the valves were in their required positions. However, these items indicated that the Tagging Request Information System (TRIS) data base was not being main-tained curren TRIS is used to conduct system lineups and system restoration following maintenance and surveillance activities. Full system lineups are normally conducted prior to startup following refueling or when directed by manage-ment. The SLC system lineup had been conducted prior to fuel load and had been verified (without alignment discrepancies) during NRC Inspection 50-354/86-2 On June 7, 1986, an inadvertent SLC actuation occurred (reference NRC In-spection Report 50-354/86-26). This resulted in a series of flushing op-erations to remove the borated solution from the SLC lines, which required a number of valve manipulations to complete. Following this activity, the system was restored to normal alignment using the TRIS system "off normal" report. The items identified above were not included in the "off normal" report and therefore were not properly restore When this was identified to the licensee, a full SLC system lineup was conducted and the discrepancies corrected. The licensee determined that the flushing evolution was not a " normal" type of maintenance activity in which TRIS, through maintenance tagging requests, would be capable of maintaining current valve position information. Therefore, Operations Department management should have required a full system lineup for proper restoration following the flushin In addition, the licensee conducted a lineup verification of the diesel generator auxiliaries satisfactoril This system was selected based on the number and types of maintenance ac-tivities that had occurred since a full system lineup was last complete Based on the licensee's immediate corrective actions, the fact that the SLC was not yet required to be operable, and that the discrepancies iden-tified would not have prevented system operation, the inspector had no further concerns at this tim During the walkdown verification of the "A" Core Spray subsystem, the in-spector noted that valves 1-BE-V117 and 118 were closed but not locke Neither the licensee's lineup procedure nor the P&ID (M-52-1) required these valves to be locked, therefore they were lined up in accordance with procedures. However, these valves are single manual isolation valves (one inch or less) that are part of the primary containment boundary. It was later determined that these valves are typical vent, drain and test con-nection valves that are located upstream of the outboard containment iso-lation valves that are listed in the plant Technical Specification There are approximately 140 similar valve These vent, drain and test connection isolation valves exist in three con-figurations as follows:

-

single manual valve with a threaded cap

_ _ _ _

. - _

.

. .

-

two series manual valves with a threaded cap

-

two series manual valves without a ca CFR 50 Appendix A General Design Criteria (GDC) require that manual containment isolation valves be locked closed. In addition, those manual isolation valves listed in the Technical Specifications are also subject to periodic surveillance to verify that they are locked closed to assure containment integrity is maintained. The licensee did not list these valves as containment isolation valves in either the FSAR or the Technical Specifications. Based on a conversation with NRR, the inspector found

'that listing of vent, drain and test connections in the FSAR and Technical Specifications as containment isolation valves was not necessary. Howev-er, these valves are considered to be part of the containment boundary and should meet the GDC. In addition, to assure containment integrity period-ic surveillance of these valves should also be conducted. The licensee is currently developing the necessary administrative controls for the vent, drain and test connection valves to meet the GDC for containment integri-t Resolution of this concern will be detailed in the next monthly in-spection repor No violations were identifie . Preoperational/Startup Testing 7.1 The licensee completed final preparations and took the reactor criti-cal at 11:18 p.m. on June 2 .2 Initial criticality was followed by a full core shutdown margin dem-onstration and a source range non-saturation demonstratio Region I inspectors provided 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> / day coverage of initial criticality ac-tivities and will have expanded coverage for selected activities throughout the icw power test program. The inspectors reviewed and witnessed the following procedures:

1) Full Core Shutdown Margin Demonstration TE-SU.ZZ-041(Q) Revision

2) Shutdown Margin Demonstration RE-ST.ZZ-007(Q) Revision 2 3) Source Range Monitor Response to Rod Withdrawal TE-SU.SE-062(Q)

Revision 2 4) Source Range Monitor Non-Saturation Demonstration TE-SU.SE-064(Q) Revision 1 5) Source Range Monitor / Intermediate Range Monitor Overlap Verifi-cation TE-SU.SE-101(Q) Revision 3 6) Startup From Cold Shutdewn to Rated Power OP-IO.ZZ-003(Q)

_

.

. .

The inspectors conducted a temporary modification audit including an ap-plicable safety evaluation review. Additional inspector coverage of ini-tial criticality is discussed in Inspection Report 86-3 No violations were identifie . Licensee Event Report Followup The licensee submitted the following event reports during the inspection period. All of the reports were reviewed for accuracy and timely submis-sion. Certain designated reports were followed up by the inspector to review implementation of corrective action. These are indicated by an asterisk belo * LER 86-012 Control Room Emergency Filtration Actuation Resulting from Equipment Failure LER 86-013 Inadvertent Isolation of RWCU System During Surveillance Testing

• LER 86-014 "D" Channel Engineered Safety Feature Actuation

• LER 86-015 Spurious "A" Channel LOCA Initiation

• LER 86-016 Control Room Emergency filtration Initiation

• LER 86-017 Inadvertent Actuation of the "A" Control Room Emergency Filter Unit During Troubleshooting

• LER 86-019 "D" Channel Engineered Safety Feature Actuation

• LER 86-020 "D" Channel Engineered Safety Feature Actuation

• LER 86-021 "D" Channel Engineered Safety Feature Actuation LER 86-022 Inadvertent Isolation of RWCU System

• LER 86-023 "B" Channel Engineered Safety Feature Actuation LER 86-024 Inadvertent "D" Channel LOCA Signal During Surveillance Testing LER 86-025 Control Room Emergency Filtration Chiller Actuation Due to Power Supply Trip LER 86-026 Automatic Start of "A" Control Room Chiller LER 86-027 Installation of Combustible Material in the Traveling Screen Motor Room

• LER 86-028 Inadvertent Actuation of "A" Channel Standby Liquid Control

. _ _ _ _ _ _ _ _ _ _ _ _ _ J

.

. .

LERs86-012 and 86-016 both detail automatic actuations of the Control Room Emergency Filtration System. The cause of both events was a faulty power supply to a detector in the Control Room Radiation Monitoring syste The power supply was recalibrated and the system restored to normal. LER 86-017 also details an automatic actuation of the Control Room Emergency Filtration system. This event occurred as a result of troubleshooting efforts to identify the cause of the event reported in LER 86-016. No further similar events have occurred; however, the licensee is continuing to monitor the system to identify any further corrective actions. Although the immediate corrective actions appear to have been adequate, the inspector will followup on the licensee's monitoring efforts during a future inspec-tion to determine if any changes to the LERs are require LERs86-014, 86-019,86-020, 86-021 and 86-023 describe spurious Engineered Safety Feature actuations. These events are all related in that the cause appears to be a pressure transient in the common sensor lines. Due to the number of spurious level related ESF actuations, the licensee formed a task team to research the problem and determine corrective actions. These actions are outlined in LER 86-019 and a review of the licensee's efforts are detailed in paragraph 9 of this repor For certain events (86-020 and 86-021), the licensee has determined the most probabl'e cause was an induced pressure transient by test personnel performing maintenance on the common sensor lines (transmitter replacement and valving operations).

LER 86-015 describes a spurious actuation of the "A" Channel Engineered Safety Features (LOCA initiation). The root cause of this event was the improper opening of an instrument root valve on the "A" channel reference leg. Details of this event are described in paragraph 3.3 of NRC Inspec-tion Report 50-354/86-26. The licensee's immediate corrective actions included walkdowns of sensing lines to find other mispositioned valves and also the implementation of the Instrument Root Valve Lineup procedur The inspector reviewed these actions and has no further questions at this time. However, the inspector will follow the licensee's long term cor-rective action to place these types of valves in the TRIS computer for better administrative control of proper alignmen LER 86-028 describes an actuation of the "A" channel of Standby Liquid Control. Details of this event are discussed in paragraph 3.3 of this report and in NRC Inspection Report 50-354/86-2 . Evaluation of Spurious ESF Actuations Since receipt of the low power operating license on April 11, 1986, the licensee has experienced five Loss of Coolant Accident (LOCA)/ Engineered Safety Feature (ESF) Actuations for which a root cause could not be deter-mined. A listing of the event dates and the affected channel is shown below:

._ . - - - _

. _ .

.

. .

PSE&G Incident Event Report No.__ Date Description 1 86-041 4/20/86 ESF Actuation on B Channel 2 86-048 4/26/86 ESF Actuation on A Channel 3 86-057 5/6/86 ESF Actuation on D Channel 4 86-064 5/13/86 ESF Actuation on D Channel 5 86-065 5/13/86 ESF Actuation on D Channel The licensee attempted to determine a root cause, however it was obvious from the event reviews that plant conditions did not warrant an ESF actua-tion since reactor vessel level was steady and well above the low-low lev-el setpoin Three possible root causes were proposed,

-

a perturbation in common sensor lines of LOCA instrumentation,

-

a perturbation in the common power supplies for LOCA instrumentation, and

-

some type of reactor vessel transien Special Test Procedure 86-05-29-112-5-1 was developed and performed in an effort to examine these possible causes. The results of this test were reviewed and discussed with the licensee system engineers onsite and also at a management meeting at the NRC Region I offices on June 5, 198 Through the process of elimination, the only feasible explanation for the ESF actuations was a perturbation in the common sensor lines of ESF/LOCA instrumentation (specifically reactor vessel level instruments). In an effort to prevent recurrence of similar events, the licensee committed to performing the following actions:

Prior to initial criticality

-

Blow back instrument lines

-

Install identification tags on LOCA/ECCS instrument sensor lines

-

Install quick disconnects on LOCA/ECCS instruments

-

Review incidents with all I&C Technicians By July 15, 1986

-

Complete installation of identification tags on RPS/NSSS instrument sensor lines

---

.

. ,

-

Review LOCA/ECCS surveillance procedures

-

Include instrument sensor valves in status log By September 1, 1986

-

Complete review of RPS/NSSS surveillance procedures

-

Complete installation of cages around LOCA instrument racks The inspector has verified that the initial criticality commitments have been satisfied and will followup on the remaining commitments in a future inspection (86-30-03).

10. Corrective Action Program The inspector conducted a review and inspection of the licensee's program for the identification and resolution of problems that could have an im-pact on plant safet The major focus was on the station Quality Assur-ance program's findings and the corrective action program. Quality

-

Assurance Procedure QAP 7-1 " Corrective Action" describes the licensee's program for identification of deficiencies and ensuring that corrective actions have been adequately implemented. There are four methods of identifying these deficiencie In order of increasing significance they are:

-

Quality Action Request (QAR)

-

Corrective Action Request (CAR)

-

Management Action Request (MAR)

-

Stop Work Order (SWO)

Since September, 1985, there have been 47 QAR's (including reissues), 18 CARS, 3 MARS and 0 SW0s issued. These action requests were found to be generally well thought out and frequently documenting concerns shared by the NR The corrective action program appears to be working satisfactorily with the exception of the timeliness of the individual department's responses to the action requests. When an action request is issued by QA, the ad-dressee is provided a " response due" date which may be as long as 25 work-ing days from the date of issue but is also dependent upon the finding's significance. The addressee may request an extension to the response due date which must be approved by QA. Of the 68 action requests issued to date, approximately 47 of the responses were submitted to QA late. As can be seen from the following partial list of overdue responses, as of June 26, 1986, some are overdue by a significant period of tim .

. ,

Deficiency Response Response Time Overdue Number Due Date Received (Working Days)

HS-85-Q001-0 9/23/85 10/22/85 21 HS-85-Q006-0 1/22/86 2/5/86 10 HS-86-Q002-0 1/17/86 3/20/86 43 HS-86-Q005-0 2/10/86 3/20/86 27 HS-86-Q006-0 2/14/86 3/20/86 23 HS-86-Q007-0 2/14/86 3/20/86 23 HS-86-Q008-0 2/14/86 3/20/86 23 HS-86-Q009-0 2/19/86 3/20/86 21

HS-86-Q014-0 3/24/86 67+

HS-86-Q016-0 4/4/86 5/1/86 19 HS-86-Q019-0 4/15/86 5/28/86 30 HS-86-QO20-0 5/1/86 6/12/86 29 HS-86-Q027-0 5/9/86 6/26/86 33 HS-86-QO29-0 6/5/86 6/26/86 15 HS-86-Q030-0 6/6/86 6/23/86 11 HS-86-C004-1 3/17/86 3/27/86 8 HS-86-C009-0 4/4/86 6/4/86 42 HS-86-C010-0 4/13/86 5/9/86 20

HS-86-C012-0 5/12/86 32+

HS-86-C013-0 6/16/86 8+

HS-86-M003-0 5/15/86 5/28/86 8

• Not received as of June 26, 1986 Timely corrective action is required by both Appendix B to 10 CFR 50 and the licensee's own procedures. The failure to take prompt corrective ac-tion is a violation (86-30-04).

11. Electrical, Instrumentation and Control Systems Branch Visit

'

During the Electrical, Instrumentation and Control Systems branch visit at Hope Creek on September 24-26, 1985, a deficiency was identified with la-beling remote shutdown station readout devices. Appropriate identifica-tior tags were not mounted at each remote shutdown station readout device for the following parameters: reactor pressure (690 A, E, J & N); reactor vessel level (621 - 691 A&A); suppression pool level indicator (P/C R609);

and suppression pool temperature (L/C R604A), A subsequent telephone con-versation between R. Lint of Bechtel, representing PSE&G, and J. Mauck of the NRC concluded that mounting appropriate tags could be deferred until up to six months after completion of fuel load. This item will remain open until the appropriate identification tags are mounted at each identi-fied readout device (86-30-05).

l 1 NRC Commissioner's Visit

!

Commissioner Asselstine met with licensee management and toured the Hope Creek facility on June 30, 1986. The tour included the control room, tur-bine deck, refueling floor, drywell and the PSE&G Nuclear Training Cente ._ _ -__

. _-.

.,

. .

13. Main Steam Isolation Valve Spring Inspection On June 6,1986, Attwood & Morrill Co., Inc. informed the NRC that cracks had been observed in four external closing springs on Main Steam Isolation Valves (MSIV) at Detroit Edison's Enrico Fermi Unit 2. The cause was de-termined to be quench cracks developed during the manufacturing proces Attwood & Morrill was the supplier for the MSIVs at Hope Creek. Both Attwood & Morrill and General Electric (GE) provided recommended inspec-tion programs which the licensee considered in developing their own posi-tion. GE's final recommendation and the inspection program accepted by the licensee was to visually inspect the accessible surfaces of all inner and outer springs for cracks or other indication If any defects are identified the spring is to be replaced with a spring that had passed the 5% overload test. The licensee will also reinspect the springs at each refueling outage to assure no new indications / defects develop. The in-spector reviewed QA surveillance report HC-86-175 which documents the vi-sual inspection of the MSIV springs. No indications were observed, and the inspector has no further question . Exit Interview The inspectors met with licensee and contractor personnel periodically and at the end of the inspection report to summarize the scope and findings of their inspection activities. Written material was not provided to the applicant during tne exi Based on Region I review and discussions with the licensee, it was deter-mined that this report does not contain information subject to 10 CFR 2 restrictions.

.

. - , - - - -