IR 05000354/1986036
| ML20209H080 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 09/04/1986 |
| From: | Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20209H042 | List: |
| References | |
| 50-354-86-36, NUDOCS 8609150153 | |
| Download: ML20209H080 (26) | |
Text
{{#Wiki_filter:. . U. S. NUCLEAR REGULATORY COMMISSION
REGION I
050354-860611 , ' 050354-860618 050354-860629 050354-860630 050354-860703 050354-860704 050354-860707 Report No.
50-354/86-36 Docket 50-354 License NPF-57 Licensee: Public Service Electric and Gas Company Facility: Hope Creek Generating Station Conducted: July 15, 1986 - August 11, 1986 Inspectors: R. W. Borchardt, Senior Resident Inspector D. K. Allsopp, Resident Inspector R. J. Summers, Project Engineer if'/[8b Approved: . - L. Nbrrholm, Chief, Prdjects Section 2B 'Ddte Inspection Summary: Inspection on July 15, 1986 - August 11, 1986 (Inspection Report Number 50-354/86-36) - ' Areas Inspected: Routine onsite resident inspection of the following areas: followup on outstanding inspection items, operational safety verification, surveillance testing, maintenance activities, engireered safety feature system walkdown, licensee event report followup, licensee identified violation, and a management meeting summary. This inspection i involved 204 hours by the inspectors.
Results: Although no violations were cited in this report, paragraphs 5 , and 8 discuss concerns that warrant prompt attention. As discussed in paragraph 5, a safety related system (Service Water) was declared operable without resolution of an outstanding Deficiency Report (DR).
This DR questioned the structural integrity of a portion of the Service Water (SW) system and should have been dispositioned prior to declaring the SW system operable. This practice was in violation of the station Administrative Procedures; however, because the station Quality Assurance Organization e609150153 860908 PDR ADOCK 05000354 G PDR
O . had recently identified a nearly identical situation the NRC will evaluate the station's corrective actions prior to making a decision on possible enforcement.
Paragraph 8 documents a number of self identified violations for which corrective actions have already been taken. While the self identification of these violations is seen as a positive indicator it also makes clear the need for an increased attention to detail in all phases of plant operations. Because the violations were promptly identified and effective corrective actions taken in a timely manner, no NRC enforcement actions will be take * . . ts DETAILS 1.
Persons Contacted Within this report period, interviews and discussions were conducted with members of the licensee management and staff and various contractor personnel as necessary to support inspection activity.
2.
Followup on Outstanding Inspection Items 2.1 Inspector Follow Items (Closed) Inspector Folicw Item (85-64-05); Reactor Core Isolation Cooling (RCIC) Pump Functional Test and Flow Verification. During the Technical Specification (TS) inspection conducted prior to plant licensing it was identified that the RCIC inservice test did not adequately address all of the TS required conditions.
The inspector has subsequently reviewed revisions to OP-IS.BD-001 " Reactor Core Isolation Cooling Pump - Inservice Test" and OP-IS.BJ-001 "HPCI Main and Booster Pump Set - Inservice Test" and verified that the required test conditions are specified in the body of these procedures. The inspector has no further questions at this time and this item is closed.
(Closed) Inspector Follow Item (86-02-01); Inservice Testing Acceptance Criteria.
The inspector reviewed various inservice test procedures for safety related pumps and verified that the acceptance criteria is now incorporated into the body of the procedure. This' ensures that the acceptance criteria and alert ranges will receive the same level of review as all other surveillance tests and the procedure will be controlled by the licensee's controlled distribution system. The inspector has no further questions at this time and this item is closed.
(Closed) Inspector Follow Item (86-20-03); High Pressure Coolant Injection (HPCI) Surveillance Tests.
During a previous inspection the inspector identified two concerns relating to the adequacy of HPCI system surveillance tests.
Surveillance Test OP-ST.BJ-001(Q) - Rev. I "HPCI System Piping and Flow Path Verification" was reviewed to verify that both injection paths (feedwater and core spray) were now properly vented and filled.
Revision 1 to this ST corrected the inspector's concern relating to adequacy of the HPCI valve lineup and prevention of water hammer events.
The inspector also reviewed OP-SO.BJ-001(Q) - Rev. 2 "High Pressure Coolant Injection System Operation" to verify that both vent paths were properly identified.
Proper operation of air operated valve F025 is now verified in procedure OP-ST.BJ-002 - Rev. 2 "HPCI System Functional Test (Low Pressure) 18 Month".
The inspector has no further questions at this time and this item is close * . . .
(Closed) Inspector Follow Item (86-20-06); Logic Power Monitor Surveillance Test.
During an inspection of surveillance tests (ST) prior to operating license issuance the inspector found that a number of ECCS logic power monitor circuits were not tested. The licensee wrote and performed ST OP-FT.ZZ-002 " Logic and Inverter Power Monitor Test" to ensure the proper operation of the logic power monitors for ADS, Core Spray, RHR, HPCI and RCIC. The inspector reviewed the ST and has no further questions at this time.
(Closed) Inspector Follow Item (86-26-02); Review QC Surveillance Report. QC Surveillance report HQC-86-628 documents a number of deficiencies identified by the inspector during observation of control rod drive maintenance (CRDM) work during May 1986.
The inspector reviewed this QC report and the licensee's corrective actions and found them to be acceptable.
In addition, QC report 86-155 was reviewed which documented the QC surveillance of CRDM work when it was recommenced.
The activities were found to be acceptable.
This item is closed.
2.2 IE Bulletins (Closed) IE Bulletin (86-BU-02); Static "0" Ring Differential Pressure Switches.
The purpose of this bulletin was to request the licensee to determine whether or not they have Series 102 or 103 differential pressure switches supplied by Static "0" Ring (SOR) Incorporated installed as electrical equipment important to safety.
In a response dated July 30, 1986, the licensee documented that Hope Creek does not use any of the subject switches in important to safety applicatic,s.
The inspector held discussions with system engineers and conducted independent plant tours to verify that SOR differential pressure switches are not used.
This bulletin is closed.
3.
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) - 1' Selected Chemistry Logs - ! Selected Tagouts - ' Health Physics Watch Log - ! 3.2 The inspectors periodically toured the plant during regular and j backshift periods. These tours included the control room.
l Reactor, Auxiliary, Turbine and Service Water buildings, and the ! drywell (when access is possible).
During the inspection, ! discussions were held with operators, technicians (HP & I&C), I , .
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mechanics, supervisors, and plant management. The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, Technical Specifications, and Station Procedures.
(1) On a daily basis, particular attention was directed to the following 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 - completion.
(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 - correct positions; Visually inspecting major components for leakage, - lubrication, vibration, cooling water supply, and general operating conditions; and, Visually inspecting instrumentation, where possible, - for proper operability.
(3) On a biweekly basis, the inspectors: Verified the correct application of a tagout to a - safety-related system; Observed a shift turnover; - Reviewed the sampling program including the liquid and - gaseous effluents;
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- Verified that radiation protection and controls were properly establi:hed; Verified that the physical security plan was being - implemented; Reviewed licensee-Identified problem areas; and, - Verified select.ed pertions of cor.tainment isolation - lineup.
3.3 Inspector Comments / Findings.: The unit entered this report period in Mode 2 with the reactor critical for power ascent, ion heatup phase testing.
During the period froa. July 15 to July 20, the unit experienced four separate automatic initiations of the High Pressure Coolant Injection (HPCI) system. During each of the events, the HPCI turbine was tripped before t.ny water was injected into tSe reactor vessel and all systenn, responced properly for the plant conditions in effect. A review d plant conditions prior to, and after the actuaticns showed that rerttor vessel water level remained within the normal range and that HPCI shculd not have received an actuotion signal.
Th0 lice.asec's investigation and a subsequent test conducted on Jsly 20, established the most, probable cause for three of these spurious actuatitsns to be workers in the drywell bumping intu eeactor vessel level sensing lines.
For the actuation on July 16, the :euso was dr.termined to be an Instrument and Controls tectnic1ar. valving error.
In an effort to prevent further spurfoos a:tuations, the licensee placed more stringent controls on access loto the drywell and
reinforced the importance of proper valve opefations to I&C technicians.
At 1:37 a.m. on July 19, the reactor s :ranmed frca approximately 0.5% power due to an operator error in the mar,ipulation of the "B" and "G" Intermediate Range Monitor (IRM) range switchas. As reactor power was being increased the "B" and "G" IRMs were simultaneously downranged instead of upranged causing the two IRM channels to go upscale and trip the A and 8 Reactor Protection System (RPS) scram channets.
The plant was placed in a stable condition and a post scram review conducted.
The reactor was taken critical at 5:51 p.m. on July 19, for continuation of the low power test program.
On July 21, a Commission nweting was held to discuss and vote on a full power license for Hcpe Creek. The Commissioners voted 4 to 0 in favor for authorizing a full power license. On July 24, NRC - Region I met with the licensee to discuss the corrective
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action program for the spurious ESF Actuations and the license was issued on July 25. Additional details on the July 24 meeting can be found in paragraph 9 of this report.
At 8:20 p.m. on July 25, a reactor scram occurred from 3% powee due to reactor vessel low water level.
Surveillance testing was in progress on the turbine stop and control valves when an operator erroneously shut the valves to start turbine chest warming. This resulted in all bypass valves opening and a reactor high water level due to swell which tripped the two operating feed pumps.
Feedwater was not restored before the reactor scrammed on low level. All systems responded normally to the scram.
Following a SORC review of the event, the reactor was made critical at 7:48 a.m. on July 26.
At 5:28 p.m. on July 29, the reactor scrammed while troubleshooting the -22 volt DC portion of the Electro Hydraulic Control (EHC) logic system. During troubleshooting, the -22 volt DC supply was lost and all bypass valves went full open causing reactor vessel level swell.
All feed pumps tripped due to the reactor vessel high water level.
The pumps were not restarted prior to receiving a low water level reactor scram.
Prior to the scram, reactor power was at 6%, prepar-ing for main turbine synchronization with the grid. The licensee commenced a reactor startup at 3:15 a.m. on July 31, and terminated startup at 4:45 a.m. when the rod position indication system (RPIS) failed. The reactor was maintained suberitical until RPIS trouble-shooting was complete and the reactor taken critical later that day.
At 5:34 a.m. on August 4, an erroneous level-1 and level-2 channel "A" LOCA signal was received when an I&C technician improperly checked a valve position causing a pressure spike to the "A" instrument rack. All equipment responded normally for plant conditions (Mode 4, reactor temperature 140 degrees F).
At 10:25 p.m. on August 5, a channel "A" primary containment isolation system (PCIS) actuation occurred which tripped reactor building ventilation fans, closed valves in the RHR and reactor water cleanup systems and started fans in the Filtration, Recirculation Ventilation System (FRVS). A low reactor vessel level " seal in" signal was generated earlier in the day during backfilling of the "A" level instrument rack. At 10:25 p.m. the "A" manual initiation pushbutton was depressed as part of an I&C surveillance test. These two signals combined to cause the channel "A" PCIS actuation. A contributing factor to this event is the fact that there is no indication easily available to the control room operator that one of the PCIS actuating signals is sealed in. Although a reactor vessel low level condition did not exist at the time of the isolation, the signal was still
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i f sealed in from earlier in the day. The station has initiated a ! Design Change Request to evaluate and possibly install an ! indicating light to alert the operator that a sealed in j actuation signal is present. The inspector will follow the i resolution of this problem (86-36-01).
At 11:45 a.m. on August 8, the licensee declared an unusual event when it was discovered that the reactor building to torus , ! vacuum breaker butterfly isolation valves (HV-5029 and HV-5031)
were inoperable and would have prevented the vacuum breakers from fulfilling their safety function. The plant was shutdown and separate investigations by the plant staff and the offsite , i safety review committee commenced.
It was determined that the i differential pressure transmitters were connected backwards, i such that the isolation valves would close as a vacuum was created in the torus instead of open as required.
This incident
j will be the subject of NRC special inspection report 50-354/86-41.
3.4 The inspector reviewed selected portions of the fire protection
program which were incorporated into the Final Safety Analysis Report (FSAR) and deleted from Technical Specifications on
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July 25, 1986.
The inspector toured the joint Salem and Hope Creek
fire station and discussed procedure implementation with the senior { fire house supervisor.
The fire station appears adequately equipped i and well organized.
Procedure implementation was found to be, con- ! sistent with FSAR requirements.
I j No violations were identified.
l 4.
Surveillance Testing i j During this inspection period the inspector performed detailed j technical procedure reviews, and reviewed in progress surveillance testing as well as completed surveillance packages. The inspector !
! verified that the surveillances were performed in accordance with i , licensee approved procedures and NRC regulations. The inspector also
j verified that the instruments used were within calibration tolerances j and that qualified technicians performed the surveillances.
- I The following surveillances were reviewed, with portions witnessed by j the inspector: ! l IC-TR.SB-007(Q) Time Response Test Reactor Protection System - - , Division 3 Channel C71-N0060 & C71-N006C I Turbine Stop Valve Closure RPS Trip EOC - RPT . System B Trip ! !
OP-ST-SN-001(Q) ADS /SRV Manual Operational Test - 18 Month - l i j OP-AB.ZZ-121(Q) Failed Open SRV ! - i l
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- OP-ST.GS-004(Q) Suppression Chamber /Orywell Vacuum Breaker Operational Test IC.FT-SE-011 IRM Channel G Functional Test - IC-TE.SE-002 NI System Division 3, Channel C APRM Temporary - Scram Clamp Adjustment IC-TR.SE-007 APRM-C Time Response Test - No violations were identified.
~ 5.
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 Specifications, and appropriate industrial codes and standards.
Portions of the following activities were observed by the inspector: Work Order Description 86-07-23-171-5 "A" Safety Auxiliary Cooling System Pipe Repair On July 28, 1986, a through wall leak was identified on the service water outlet pipe from the A-1 Station Auxiliaries Cooling Water System (SACS) Heat Exchanger. A work order was established to inspect and repair the pipe. Based on examination the licensee found that the protective lining (a phenolic coating) had been eroded away and that the base metal of the pipe had experienced a corrosion / erosion attack. The af fected area appeared to be limited to a small region of the pipe wall where the service water flow was directed by a flow balancing, throttling valve on the outlet of the heat exchanger. The licensee effected a temporary repair by use of a welded external patch over the affected area. This repair was to permit operation of the system for approximately 1 to 2 weeks until the station entered an outage following the completion of the low power testing plateau.
l Based upon the extent of the damage to the pipe, the licensee decided l to examine the outlet legs of the "B-1" and "B-2" SACS heat exchangers. Conditions similar to, but not as extensive as on A-1 ! l were found. Damage to the valve seat, phenolic coating and pipe wall l were all noted and Deficiency Reports were written on the identified ! nonconforming conditions. The "B" SACS heat exchanger was placed in i service (and declared operable) without any repairs at the time, ' since the damage was not as extensive as determined by the visual exams, , } I !
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The inspector questioned the determination to declare the system operable without resolution of the DR's.
No evaluation or tests of the structural integrity of the pipe had been conducted prior to returning it to service.
This type of evaluation appeared to be a requirement of Station Administrative Procedure (AP.ZZ-020). The inspector discussed this finding with the station QA engineer to see if similar findii.gs had been noted by QA. At the time, a Corrective Action Report (CAR) was in preparation which discussed a similar ' occurrence where the HPCI system was declared operable with a DR still unresolved due to overpressurizing the discharge piping during testing. CAR-HS-86-020-0 was issued (after including the service water pipe issue) tu the station on July 30, 1986.
During the outage conducted August 1986, repairs were made to the affected service water pipe.
This included building up the wall of the pipe with a weld overlay and restoring a protective lining to the area by applying Belzona epoxy to the pipe. Based on previous experience the licensee has determined that Belzona epoxy is very resistant to the erosion effects of the service water.
The inspector will follow the licensee's long term corrective actions for the throttling valves and also the response to the CAR to prevent future occurrences (86-36-02).
No violations were cited.
6.
Engineered Safety Feature (ESF) System Walkdown The inspectors verified the operability of the selected ESF system by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match plant drawings and the as-built canfinoration. This ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to i verify that valves are properly positioned and locked as appropriate.
! The "A" Loop of Low Pressure Coolant Injection (Residual Heat i Renoval) was inspected.
, i Prior to the inspector's systen walkdo,<n, the licensee identified ! flenge leaks en the Residual Heat Removal (RHR) system on two separate u ! occasions. An inve.stigation determined the flange bolt torque i settings on the leaking flanges were significantly below PSE&G's maintenance program requirements. The resident insrectcr asked the system engineer if there was a generic problem and if so, what was i
being done to correct the problem. After an investigation, the system engineer cor.cluded that the arch:tect engineer (Bechtel) ed i , { ro torque specifications for flanges on systems rated under 600 psty (this includes RHR). To verify piping integrity on these systens I prior to turnover from Bechtel to PSEt;G, a nydrostatic test was ! performed in accordance with Bachtel Test Speciffcation l 10855-P-590(Q). Threugh established leakage criteria, the l
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hydrostatic test was utfif zed to verify system integrity.
PSE&G has a well defined maintenance program which includes torque specification for all bolts, nuts, and fasteners regardless of system rated pressure. The system engineer initiated work orders to check torque specifications on all flanges in core spray and RHR piping greater than one inch diameter.
The licensee determined that torque settings varied widely on any given flange and that the average as-found torque was roughly one-half the torque required by PSE&G's maintenance program.
No violations were identified.
7.
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 submission. Certain designated reports as indicated by an asterisk, were followed up by the inspector for corrective action implementation.
- LER 86-18 Failure of Ser'vice Water Strainers LER 86-29 Automatic-Start of "B" Control Area Chiller LER 86-30 Automatic Start of "B" Control Area Ventilation Train
- LER 86-31 Reactor Scram Due to Personnel Error in Ranging IRMs
- LER 86-32 Initiation of Manual Scram for Troubleshooting of Reactor Manual Control System
- LER 86-33 Inadvertent "B" Channel LOCA Signals During Instrument Calibration Performance
- LER 86-35 Reactor Scram Signal Originating From the Neutron Monitoring System LER 86-36 Isolation of the "A" Control Room Ventilation Unit Due to Radiation Monitor Upscale Trip LER 86-18 describes the failure of the "A" and "C" station service water pump discharge strainers due to a loss of the self-cleaning mechanism.
Insufficient clearance between the port adjustment shoe and the strainer resulted in the port adjustment shoe striking the strainer and caused binding of the self-cleaning mechanism. This binding resulted in a loss of backwash capability and a high differential pressure across the strainer.
The root cause has been determined to be a mechanical failure of the strainer element due to e design deficiency of the clearance between the port adjustment shoe and the strainer element. The licensee's :orrective action included
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. 'll replacement of both strainer elements and increasing the clearance between the adjustment shoe and the strainer element per the manufacturer's recommendation.
LER 86-31 describes a reactor scram at 1:12 p.m. on June 29, 1986, as a result of an upscale trip on the "D" Intermediate Range Monitor (IRM). The upscale trip occurred as the control operator ranged down IRM "0" from range 2 to range I with an IRM reading of 38 on range 2.
The " shorting links" were removed in support of shutdown margin demonstration and thus a single IRM trip resulted in a full scram.
The licensee counselled the control room operator on the need to carefully review indications and will review the incident with the Nuclear Training Center for inclusion in appropriate training programs.
LER 86-32 describes a manual scram initiated on June 30, to troubleshoot Reactor Manual Control System (RMCS).
The reactor was manually scrammed due to the normal shutdown method (control rod insertion) being precluded by a malfunction of the RMCS.
Station I&C technicians troubleshot the system while the plant remained in operationa,1 Mode 2, but were unable to repair the system. When all avenues for repair available with the unit operating were exhausted, a manual scram was inserted to complete RMCS repairs.
The control rods were always "trippable", however, normal rod movement was prohibited due to a faulty transmitter card in the RMCS. The licensee replaced the faulty transmitter card and verified proper, operation of RMCS. The inspector has no further questions at this time.
LER 86-33 details two separate actuations of "B" Channel Loss of Coolant Accident (LOCA) logic due to incorrectly returning a level instrument to service.
In both of the actuations I&C technicians were returning post accident monitoring level transmitter BB-LT-3682 B to service following calibration activities. Although this transmitter is not a Technical Specification surveillance related instrument, it shares common variable and reference sensing lines with a number . of ECCS level transmitters. Also, since this transmitter is not part of the ESF protection system, it was being calibrated using , ' a general vice specific procedure and performed by technicians who had not received the specific surveillance training for Technical Specification Surveillance Tests. The root cause has been iden-tified as personnel error on the part of the I&C technician in performance of valving, in conjunction with a procedural inadequacy regarding the type of procedure that should be used. The licensee's corrective action include identifying and treating all non-surveil-lance instruments which interface with ECCS and ESF instrumentation '. as if they were surveillance equipment.
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P LER 86-35 describes a reactor scram which occurred on July 4,1986.
A half scram was manually inserted prior to the event to comply with an action statement associated with inoperable reactor protection system instrumentation. The scram occurred when a concurrent half scram signal was generated from average power range monitor channel "E" due to a momentary upscale spike of local power range monitor (LPRM) IC-24-57. The I&C department has determined that the momentary spike was spurious and of unknown origin. The licensee could find no equipment malfunction and the event has not recurred.
S.
Licensee 14entified Violations During this report period the licensee identified four instances where the requirements of Technical Specification (TS) were not satisfied.
The licensee's findings are documentad in licensee generated incident reports and are summarized below.
Incident Report No.
Event Date Description 86-156 8/1/86 Reactor sample valve time response test not performed in a'ccordance with TS 3.3.2.
86-159 8/3/86 The Safety Auxiliary Cooling-System (SACS) to Turbine . Auxiliary Cooling System (TACS) isolation valves were found to be inoperable due to shut hydraulic control valves and removed control power fuses.
It could not be immediately determined how long SACS had been inoperable.
86-164 8/8/86 Failure to enter the appropriate TS Action Statement after exceeding the allowable 2 hour period for a reactor pressure instrument - channel calibration.
86-165 8/8/86 Failure to satisfy TS Action Statement 3.3.7.9 while various ventilation radiation monitors were inoperable - - . _ _ __ __.. __ .. . . .
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Because the licensee promptly identified the above discrepancies and then took the appropriate corrective and preventive measures, no enfor-cement action is appropriate in accordance with 10 CFR 2, Appendix C.
However, these instances do highlight the need for additional attention to detail in all aspects of plant operations.
9.
Management Meeting On July 24, 1986, a meeting was held between Public Service Electric and Gas Company and the NRC Region I staff in King of Prussia, Pennsylvania.
The purpose of the meeting was for PSE&G to present their short term and long term corrective action programs to prevent numerous unexplained spurious ESF actuations.
The licensee discussed each of the following areas: I - Summary of all previous ESF actuations since Hope Creek received i a low power license including type of actuation, root cause, and corrective action; Comparison of Hope Creek's ESF instrumentation, I&C training, - and ESF-Related problems to Limerick and Shoreham; Implementation schedule for corrective action program including - interface with test schedule and outage activities.
Tne Region I staff was satisfied with pSE&G's corrective actions regarding the ESF actuations and a full power license was issued on July 25, 1986.
The list of attendees and a copy of all handouts provided by PSE&G during the meeting are provided as enclosure (1) to this report.
10.
Exit Interview The inspectors met with licensee and contractor personnel ! l 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 licensee during the exit.
t Based on Region I review and discussions with the licensee, it was j l determined that this report does not contain information subject to 10 CFR 2 restrictions.
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. -- . -. -- . . u Enclosure 1 July 24, 1986 Meeting Between PSE&G and NRC Region I > List of Attendees Name Title Organization , T. Murley Regional Administrator NRC Region I R. Starostecki Director, Division of Reactor Projects NRC Region I . W. Johnston Deputy Director, Division of Reactor NRC Region I ' Safety S. Collins Chief, Reactor Projects Branch 2 NRC Region I .I L. Bettenhausen Chief, Operations Branch, DRS NRC Region I L. Norrholm Chief, Reactor Projects Section 2B NRC Region I ! P. Eselgroth Chief, Test Programs Section NRC Region I D. Allsopp Resident Inspector, Hope Creek NRC Region I C. A. McNeill Vice President - Nuclear PSE&G S. LaBruna Assistant General Manager - PSE&G Hope Creek B. A. Preston Manager - Licensing & Regulation PSE&G A. Giordano Nuclear System I&C Engineer PSE&G P. Opsal Senior Staff Engineer PSE&G/ System Engineer G. Peet Lead I&C System Engineer PSE&G/ System G. Tenenbaum Principal Engineer PSE&G ,
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~~ ,. . NRC REGION I/PSE&G ESF MEETING THURSDAY, JULY 24, 1986 AGENDA I.
INTRODUCTION II.
SUMMARY OF PREVIOUS ESF ACTUATIONS III.
COMPARIS0NS TO LIMERICK & SHOREHAM III.
SHORT TERM /LONG TERM PROGRAM IV.
TEST SCHEDULE & OUTAGE ACTIVITIES V.
SUMMARY / CONCLUSION - . _, - _.. _. -_ - - - -- -- - - - - - -, _ _ _ _ _ - _ _ _ _-- _, ---.-,,-_a.
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IR/12R REA TYPE OtP ACIUATICN IWX7f CAUSE CURRKTIVE ACTtiYl ...... 86 458/86-015 A Onannel IDCA: A Diesel Generator start Instrtsnent root valve cut in too Performi valve linetsp, approved valve l ievo (05/06/96) and A EQ:S start...no injection since quickly (pressure spike) subject prnor.vn valves beinq ntsnherol arvi inch +1 in Bx preneure was greater than the low valve and similar valves had not TRIS prmram, preneurs setpoint.
been aligned properly.
96-069/86-028 D Otannel IOCA: D Diesel Generator start I&C Testing incbced pressure See IOCA Task Force Reconwalations.
_.. (OV15/96) and BCES initiation signal.(Ptaps OOS) transient on D channel, 86-671/86-021 D Otannel IOCA: D EU:S start...no injec-Iriproper instnsnent cut-in by I&C Technician training anri IOCA Task Fort (OV15/86) tion since Rx pressure was greater than I&C technician.
Recnnwnlations the lor p:eesure setpoint. D Diesel was tagged OOS, (no start).
! 36-078/86-024 D Onannel LOCA: D EQ3 start, Injection Iriproper instrtsnent venting on I&C Procedure revised.
(OV25/86) valves tagged shut, D Diesel tagged OOS.
cut-in by technician.
86-110/ B Oiannel IDCA: B Diesel start, B ECCS Iriproper instnsnent cut-in by Identified all instrisnents which share r"t - ! _ _., (07/03/86) start. 6000 gals injected to Rx.
IEC technician on one channel erence/ variable leg with IOCA/RPS inst riseo' caused pressure spike on IOCA and preparing specific procalures for sia channel.
Inst rtsnents.
96-111/' 8 Otannel IDCA: R Diesel start, R ECCS Same as 86-110 Same as R6-110 . _._ (07/03/86) start, 1000 gals injected.
86-136/ C Otannel IDCA: HICI start, no Inst rirent cut-in to quid ly try See ! ' * 7 ric e,, i ..._.. -.... -. (07/15/96) Injection.
I&C technician.
' _ _ _ _ _ _.. -. _ _. 86-041/86-007 B Channel IDCA: B Diesel start, R ECCS Root cause initially unknrwn... ACrlitM TAKFN/PlUNMFNIEI): (04/20/86) actuation signal, pums tagged out, Task Force established to inves-
- Blrwback inst risnent lines M ARI SCRAM tigate the events. Review of de-g
sign drawings and plant instal-
- ID taos on instrisaents 8 W /86-010 A Otarinel IDCA: A Diesel start, A ECCS lations was made, as well as in-(04/26/85)
ar*u=* ion signal, pumps tagged out, plant testing and monitoring.
- Ouick disconnects on IOCA/FRS instriswnts NG ARI SOtAM.
Events attributed to a combina-- tion of procedural problem, air
- Review events with I&C Technicians 86-057/86-014 A Onannel IOCA: A Diesel start, A ECCS in instnsnent lines, and control (OV06/96)
actuation signal, puips tagged cut.
of instrtsnent racks and valves.
- Upgrade procedures 86-064/86-049 D Onannel IDCA: D, Diesel start, D EOs
- Include valves in status log and actuation signal, piaps tagged out...
86-065/86-019 DD IIE*IIMBf!S ON SME IER (OV13/86)
- InstilI cageis around instnsnent racks
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' ? , t asfact 6 IDCA - 10004 CMJ:% . . f .- IM K).
TYPE OF ACTUATION RDT CNJSE COMerrIVE ACTIOd - . - - -. s 86-131/ A Onsnnel IICA: A Diesel Generator Start Air in instrument lines latest Task Pbrce rtxnuaendation . (07/14/86) and A ECQi start!. 5200 gals injected ' 86-135 C Otsunal 14CA: PPCI start Worker stepped cn instrtment latest Task mrce recarendation . (07/15/86) no injection sensing line caustry spike
, 86-138 C Onanmel toCA: leCI start' . * (07/15/86) no injection-l 86-14V C Onannel ILCA: leCI start i ' (07/30/86) no injection t
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TYPE: OF CIUATitrJ ! RUr CANK O etriIvM rrliN ! 86-h37/86-003 SCmM SIGNAL: Neutron Pbnitorinj System, I&C TEKlinician t19m91 IM Signal IbC hhnician5r hinierf ani & Sign 6 = ' ii (OV15/86) (no rods withdrarn) cable musing snik-. to prot.ct canlo-86-038/8 tr-004 Scam SIG4AL: Neutron Honf torinj Systen, Faulty gain switch on LPIN.
R pl+wi arsi caliar it *1 f.Pm auxiliar/ l ' (OV16/05) (no rods wiotndrawn)
_ _ _.. -... . ._ l 86-047/36-009 Scam SIG4AL: sane as 86-037/86-003.
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- g (04/25/16)
l-86-076/8'e023 SCRM SIGNAL: B Channel low Ik level *.. Imprrper valviry in of tranvit-See I;ra rmk P' ' =ve* stat ions.
I (05/19/86) with A Channel in trip ( APM testtry) ter on H level Chairs *l.
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- 1his is ategorized as a UEA sigrail y,
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_ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ - _ _ - _ . .,, COMPARISONS WITH OTHER HWR PLANTS Sheet 1 of 5 HOPE CREEK LIMERICK SHOREHAM COMMENTS Air in the Line YES YES YES Problems Blow Back Lines
- Blow Back Lines Blow Back Lines (As Needed)
Each Time Down (As Needed) Type of Plant /AE BWR/Bechtel BWR/Bechtel BWR/S&W RFI/EMI Problems NO NO NO (At the Pracess Instrumentation) Sloping GE Instr.
1/2" Some 1/2" Some 1/4" Some Violations Violations Violations Ref/Varible Legs 4/4' 4/2 2/2 Condensate Chambers 2" Dia. approx. 3' 2" Dia, approx. 3' 2" Dia, approx. 14' from vessel, good vessel, good slope.
from vessel, poor slope.
Free moving.
Free moving slope was corrected.
Free moving Insulation of NO? YES?
- Yes because of the Sensing Line long lines and Between Vessel and problems they have CC.
had.
Instrument Piping 1" approx.
1" approx.
1" approx.
In Drywell 80'-100' 20'-40' 20'-30' Excess Flow 1" Dragon Auto 1" Morata Manual 1" Dragon Auto Check Valves Bypass Bypass Bypass Instrument Tubings 3/8" From 1/2" from EFCV 3/8" trom Outside ot Drywell EFCV to Instr.
to Instr Rack EFCV to Rack Instr. Rack Approx. Length 175'-250' 150'-175' 150'-175' to Instr. Line . .
_______ ____ - __ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -_.
. . COMPARISONS WITH OTHER BWR PLANTS (CONT.)
Sheet 2 of 5 HOPE CREEK LIMERICK SHOREHAM COMMENTS Type of Instr.
Rosemount 1153B Rosemount 1151 Rosemount 1151/1152 Time Constant Fix 20 Msec. Narrow Adjustable Adjustable 50 Msec. Wide Range Set at 50 Msec.
Set at 50 Msec.
Flex Hose YES Yes, But not Yes, had problems (Typical) used replaced two Barton Instr.
Yes, valved out Yes, valved out Yes, replaced with In Line with RPS Rosemount Instr.
Instruments Training of Techs.
YES
- Yes.
Required YES to take 4 Hrs. of Vlv. Training Rack Design GE, protection GE, No protection GE, No protection around racks Problems with None Identified None Identified None Identified Bumping Racks Labeling at Standard Instr.
- Excellant.
Standard Instr.
I.D.
Local Rack Indentification Instrument Ident.
Red Warning Sign IEC only, valve position, T.S.
Instr. - Indentified EO Instr. - Indentified , e
-
. - COMPARISONS WITH OTHER BWR PLANTS (CONT.)
Sheet 3 of 5
HOPE CREEK LIMERICK SHOREHAM COMMENTS Manifold Valves Hoke needle Dragon tight Dragon Floating needle Needle, being replaced with metering valves Probems with YES
- Yes. Training YES Valving In/out Helped.
Instrumen;s Working on Instr.
YES
- 30. Work on No.
Work on problems At Power Problems only only when down when down Pressurize NO Yes (Helped)
- Yes (Helped)
Insturment before returning to service Design changes made Added Ouick Add head tanks NONE to prevent air Disconnect to vent valves l problems Fittings at vent Valves Troubleshooting: Walked all Yes (N5 program) YES YES instrument lines: Take Temperature Ongoing ? YES Readings.of the Instrument
Line Inside Drywell . .
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TASK SCHEDULE ACTION ITEMS . PRE OUTAGE DURING OUTAGE POST OUTAGE
Revise backfill procedure Backfill all lines !
Upgraded training techniques Upgraded training techniques
Stop work on Non-Tech Spec Expand scope of review 9/30 instruments i Issue unique procedures Work unique procedures by trained technicians
Add temporary labeling to Add warning labels to critical instruments instrument lines Add permanent labeling to all critical instruments 9/1
Test rack for instrument valves 10/30.
Modify existing manifold valves if required.
.
Design insulation Install insulation
Walk down i ns trume nt lines Walk down instrument lines Prepare design changes, if i required.
- Develop test program Install test equipment Install GETARS 9/1 less GETARS Monitor System with test program.
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