IR 05000334/1985018
| ML20135H692 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 09/10/1985 |
| From: | Lester Tripp, Troskoski W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20135H683 | List: |
| References | |
| TASK-***, TASK-TM 50-334-85-18, IEB-79-06A, IEB-79-6A, IEB-79-6A-R1, NUDOCS 8509240134 | |
| Download: ML20135H692 (27) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-334/85-18 Docket No.
50-334 Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279
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Facility Name: Beaver Valley Power Station, Unit 1 Location:
Shippingport, Pennsylvania Dates:
J ly 27 - August 31, 1985 h'..b.Ath MfW Inspector:
M. Tr
'oski, Senior Resident Inspector
' [ Tate Approved by:
Ad30
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t. E. Tri$$, Chief, Reactor Projects Section 3A,
' Dite Inspection Summary:
Inspection No. 50-334/85-18 on July 27 - August 31, 1985.
Areas Inspected:
Routine inspections by the resident inspector (101 hours0.00117 days <br />0.0281 hours <br />1.669974e-4 weeks <br />3.84305e-5 months <br />) of licensee actions of previous inspection findings, plant operations, surveillance activities, related corrective maintenance, housekeeping, fire protection, radio-logical controls, physical security, engineered safety features equipment, update of TMI Action Plan Items, review of licensee event reports, and operating procedure conformance to FSAR assumptions.
Results:
One violation was identified:
wrong security badge issued (detail 3c).
The inspector performed an extensive review of the August 29, 1985, safety injec-I tion event, and multiple plant equipment failures (detail 3.b.2), and a decline in ~the emergency diesel generator start reliability factor (details 5.c.d.e).
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TABLE OF CONTENTS
_P.a21 1.
Persons Contacted....................................................
2.
Followup on Outstanding Items........................................
3.
Plant Operations.....................................................
a.
Genera1.........................................................
b.
Operations......................................................
c.
Plant Security / Physical Protection..............................
d.
Radiation Controls..............................................
e.
Plant Housekeeping and Fire Protection..........................
4.
Engineered Safety Features (ESF) Verification........................
5.
ESF Equipment Status.................................................
a.
Ri ve r Wate r Se al Li ne s..........................................
b.
Station Batte ry 3 and 4 Update..................................
c.
Diesel Generator Air Start System...............................
d.
Diesel Generator Start Re1ays...................................
e.
Diesel Generator Governor Start Failure.........................
6.
Status of TMI Action Plan Requirement................................
7.
Updated Final Safety Analysis Report Assumptions.....................
8.
Inoffice Review of Licensee Event Reports (LERs).....................
9.
Exit Interview.......................................................
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DETAILS
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1.
Persons Contacted J. J. Carey, Vice President, Nuclear Group R. J. Druga, Manager, Technical Services T. D. Jones, General Manager, Nuclear Operations W. S. Lacey, Plant Manager J. D. Sieber, General Manager, Nuclear Services N. R. Tonet, General Manager, Nuclear Engr. & Constr. Unit J. V. Vassello, Director, Nuclear Safety The inspector also contacted other licensee employees and contractors during this inspection.
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2.
Followup on Outstanding Items The NRC Outstanding Items (OI) List was reviewed with cognizant licensee per-sonnel.
Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field'inspec-tion to determine whether licensee actions specified in the OI's had been satisfactorily completed.
The overall status of previously identified in-spection findings were reviewed, and planned and completed licensee actions were discussed for those items reported below:
(Closed) IFI (85-17-06):
Determine whether recirculation spray heat exchanger (RSHX) diaphrams could fail during initial LOCA testing conditions.
During Type A containment leak rate testing at a similar facility, excessive in-leakage was discovered through one of the RSHXs.
Removal of the bottom chan-nel cover revealed that its 1/8" seal diaphram had ruptured and leaked due to the 45 psid between the external containment pressure and the service water side of the diaphram. This condition typically occurs during the Type A tests when containment is pressurized to the design limits, and is expected during
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early LOCA conditions prior to river water fill of the RSHXs during initiation
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of containment spraydown.
The inspector discussed this matter with Engineering personnel from NECU and reviewed Beaver Valley's manufacturer's approval prints, Form U/1, from the manufacturer's data report for pressure vessels and the heat exchanger speci-fication sheet.
This indicated that the design of Beaver Valley's RSHXs em-ploys a 1/4" seal diaphram of a different geometric configuration that would preclude a similar failure. This design was incorporated to specifically meet a maximum external pressure of 48 psi, which is equivalent to the peak pres-sure during a designed based accident, and a maximum internal pressure of 150
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psi. This failure mode is therefore, not applicable to Beaver Valley and the item is closed.
(Closed) Unresolved Item (84-04-06):
Review seismic qualification of river water pump seal lines.
See detail 5.c of this report for discussion.
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(Closed) IFI (85-17-01):
Review 10 CFR 50.59 evaluation, should batteries No. 3 and 4 be replaced with the plant in Modes 1-4.
See detail 5.b of this report'for discussion.
(0 pen) Unresolved Item (85-17-02):
Verify that seismic calculations consider the non yielding effects of the support frame on station battery end cells.
See detail 5.b of this report for discussion.
(0 pen) IFI (84-22-01):
Review long term corrective actions associated with emergency diesel generator start relay reliability.
See detail 5.d of this report for discussion.
3.
Plant Operations a.
General Inspection tours of the plant areas listed below were conducted during both day and night shifts with respect to Technical Specification (TS)
compliance, housekeeping and cleanliness, fire protection, radiation control, physical security and plant protection, operational and main-tenance administrative controls.
Control Room
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Primary Auxiliary Building
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Turbine Building
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Service Building
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Main Intake Structure
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Main Steam Valve Room
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Purge Duct Room
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East / West Cable Vaults
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Emergency Diesel Generator Rooms
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Containment Building
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Penetration Areas
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Safeguards Areas Various Switchgear Rooms / Cable Spreading Room
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Protected Areas
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Acceptance criteria for the above areas included the following:
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Technical Specifications (TS)
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BVPS Operating Manual (OM), Chapter 48, Conduct of Operations
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OM 1.48.5, Section D, Jumpers and Lifted Leads
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OM 1.48.6, Clearance Procedures
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OM 1.48.8, Records
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OM 1.48.9, Rules of Practice
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OM Chapter 55A, Periodic Checks, Operating Surveillance Tests
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BVPS Maintenance Manual (MM), Chapter 1, Conduct of Maintenance
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10 CFR 50.54(k), Control Room Manning Requirements
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BVPS Site / Station Administrative Procedures (SAP)
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BVPS Physical Security Plan (PSP)
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Inspector Judgement
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b.
Operations The inspector toured the Control Room regularly to verify compliance with NRC requirements and facility technical specifications (TS).
Direct ob-servations of instrumentation, recorder traces and control panels were made for items important to safety.
Included in the reviews are the rod position indicators, nuclear instrumentation systems, radiation monitors, containment pressure and temperature parameters, onsite/offsite emergency power sources, availability of reactor protection sys,tems and proper
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alignment of engineered safety feature systems. Where an abnormal con-dition existed (such as out-of-service equipment), adherence to appro-priate TS action statements were independently verified.
Also, various operation logs and records, including completed surveillance tests, equipment clearance permits in progress, status board maintenance and temporary operating procedures were reviewed on a sampling basis for compliance with technical specifications and those administrative con-trols listed in Paragraph 3a.
During the course of the inspection, discussions were conducted with operators concerning reasons for selected annunciators and knowledge of recent changes to procedures, facility configuration and plant conditions.
The inspector verified adherence to approved procedures for ongoing ac-tivities observed.
Shift turnovers were witnessed and staffing require-ments confirmed.
Except where noted below, inspector comments or ques-tions resulting from these daily reviews were acceptably resolved by licensee personnel.
(1) During performance of MSP 21.09 on August 5, 1985, main steam pres-sure circuit card PC-MS-496D failed to trip at the 99 lb./second steam line isolation setpoint.
The inspector observed subsequent troubleshooting performed under the guidance of the 18 month cali-bration procedure (MSP 21.27).
A faulty lead-lag circuit card was identified and replaced.
During the time the loop was out of ser-vice, the inspector verified that appropriate bistables were tripped per TS 3.3.2.1 Action Statement No. 37.
The loop was returned to service on August 9, 1985.
In reviewing the operability requirements of the high steam pressure rate circuits, it was noted that TS Table 3.3-3 required the loop to be operable in Mode 3 when below the P-11 setpoint with the safety injection on low steam pressure manually bypassed, and at all times in Mode 4.
However, the ESF instrumentation surveillance requirement of TS Table 4.3-2, only requires this function to be checked when the plant is in Modes 1 thru 3.
This inconsistency was brought to the licensee's attention for corrective action.
Review of DLC's disposition is Unresolved Item (85-18-01).
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(2) Safety Injection - Reactor Trip At 12:50 p.m. on August 29, 1985, a low steam line pressure safety injection (SI)
reactor trip occurred from full power.
The in-spector observed the control room operators initial actions taken to stabilize the plant in hot standby (Mode 3) conditions.
An Un-usual Event was declared at 1:00 p.m. due to the SI.
It was sub-sequently terminated at 1:15 p.m. af ter the licensee identified the initiating event.
Cause A heater control on an ' instrument air dryer malfunctioned and over-heated an adjacent solder fitting on the main two inch air header.
When the fitting separated, the main instrument air compressor tank rapidly blew down. This pressure loss to the air-to-open main steam isolation valve (MSIV) actuators allowed the valves to flutter.
The B MSIV was the first to drop, resulting in the low steam line pressure transient (500 psi lead-lag compensated setpoint)-sensed by the C loop as the turbine governor valves opened in an attempt to maintain load.
Minimum ' steam generator (SG) pressure was 660 psi.
I Feedwater Recovery The safety injection initiated a' feedwater isolation which consisted of tripping the two main feedwater pumps (FW-P-1A,B) and associated discharge valves (MOV-FW-150A,B) to prevent an overcooling transient.
Make up was provided to the SGs by the three auxiliary feedwater pumps, which functioned properly. After resetting the SI, FW-P-1B was started and MOV-FW-150B opened for restoration of normal feed-water alignment.
Concurrent with this action, primary system tem-perature was recovered from 510F to 541F.
The combination of in-creased primary heat input and feedwater flow to the SGs resulted in a high SG level (75%) feedwater isolation.
After SG 1evels were returned to normal, the licensee again attempted to restore normal feedflow with FW-P-1B, but MOV-FW-1508 failed to open. The B pump was then shut down and the A pump started.
How-ever, MOV-FW-150A also failed to open upon demand.
Operators were immediately dispatched to manually open it.
Normal feedflow was established at about 1:40 p.m.
Investigation revealed that the torque bypass switch failed to stay in long enough to allow the B valve to come off of its back seat.
The licensee readjusted it and successfully cycled the valve several times.
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The failure of the other valve was apparently unrelated as the motor's~ rotor was found damaged when disassembled.
It was replaced-with a spare.
Low Head Safety Injection Pumps Both of the LHSI pumps (SI-P-1A,B) were started by the SI and run for about 7 minutes before being secured.
Sometime after plant stabilization, operators noted that an abnormally high number of safeguard sump alarms were coming in.
Investigation revealed that water was spraying from what appeared to be the seal packages of both LHSI pumps.
After attempts to reset the seals by bumping the pumps failed, the suction path from the RWST was isolated for both pumps at 10:30 p.m on August 29, 1985. The plant was subsequently placed in cold shutdown at 12:20 a.m. on August 31, 1985, to comply with the action statement of TS 3.5.2, ECCS Subsystems.
Maintenance personnel later determined that the source of the leak-age was from a failed 0-ring and gasket arrangement on several of the nine control rods that penetrate the casing of each pump.
These rods were added as part of a modification in 1980 to adjust wedges that are intermittently spaced along the deep shaft pump casing to dampen any vibration during a seismic event. The inspector observed portions of the corrective maintenance.
Upon completion, the in-spector witnessed the 30 minute test run per OST 1.11.1, SI-P-1A Test, on August 31, 1985.
No leakage was observed, and the A LHSI subsystem was declared operable.
Review of licensee action to assure that the failed 0-rings and gaskets are replaced on some frequency prior to the expiration of their useful life is Unresolved Item (85-18-02).
Residual Heat Removal System During the plant cooldown evolution of August 30, 1985, control room personnel attempted to place the A RHR subsystem on line.
Initial attempts to start the A RHR pump failed due to an overcurrent pro-tection relay tripping on one phase. The B subsystem was placed in service while troubleshooting. After swapping the phase lines between relays, the licensee was able to start the A pump.
From discussions with licensee personnel, it appears that one phase draws slightly more current on pump startup than the other phases and that its protection relay setting tolerance could have been at the lower end.
Review of further licensee action to determine the cause of relay actuation to assure RHR pump start reliability is Unresolved Item (85-18-03).
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Steam Generator Atmospheric Dump Valves After the MSIVs shut, the SG atmospheric dump valves limited SG pressure to the 1005 psig no-load setpoint, thereby preventing a challenge of the main steam safety valves. Discusr. ions with control
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room personnel shortly after the event indicated that the B valve
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failed to open.
However, the capacity of the A and C valves was sufficient to limit RCS temperature and SG pressurin to below the SV setpoints (1075 psig for first SV).
Discussions with I&C indi-cated that a failed I/P converter was replaced in the control loop, and the valve was successfully cycled several times.
c.
Plant Security / Physical Protection.
Implementation of the Physical Security Plan was observed in the areas listed in paragraph 3a above with regard to the following:
Protected area barriers were not degraded;
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Isolation zones were clear;
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Persons and packages were checked prior to allowing entry into the
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Protected Area; Vehicles were properly searched and vehicle access to the Protected
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Area was in accordance with approved procedures; Security access controls to Vital Areas were beirg maintained and
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that persons in Vital Areas were properly authorized; Security posts were adequately staffed and equipped, security per-
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sonnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and Adequate lighting was maintained.
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THE REMAINDER OF THIS PAGE
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THIS PAGE CONTAINS SAFEGUARDS
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d.
Radiation Controls
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Radiation controls, including posting of radiation areas, the conditions
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of step-off pads, disposal of protective clothing, completion of Radi-ation Work Permits, compliance with the conditions of the Radiation Work i
Permits, personnel monitoring devices being worn, cleanliness of work areas, radiation control job coverage, area monitor operability (portable
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and permanent), area monitor calibration and personnel frisking proce-
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dures were observed on a sampling basis.
The inspector observed licensee actions with regard to a Class B waste
shipment (RSR 0809) on July 29, 1985.
Survey activities and QC inspec-
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tions were. conducted as required. The initial survey found a hot spot around the center weld of the container that was about 380 mR/hr.. on contact, which is in excess of the 200 mR/hr. limit.
Additional shield-
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ing was added to bring down the maximum dose rate to 80 mR/hr. on contact.
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Licensee actions were satisfactory, i
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No discrepancies were observed.
e.
Plant Housekeeping and Fire Protection i
Plant housekeeping conditions including general cleanliness conditions
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i and control of material to prevent fire hazards were observed in areas I
listed in Paragraph 3.a.
Maintenance of fire barriers, fire barrier
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penetrations, and verification of posted fire watches in these areas were 3-also observed.
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During routine plant tours, improved housekeeping conditions were noted in most areas.
One item that still needs increased attention from sta-
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tion personnel is liquid spills, especially in rad controlled areas.
Two examples identified during this inspection period included a non-
l radioactive filtered water line leak (722 level, PAB) and hydraulic fluid leak from snubber WR-HSS-3038 on the river water system.
Both items were
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i promptly corrected when brought.to the licensee's attention.
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Engineered Safety Features (ESF) Verification
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i The operability of the Quench Spray System was verified on August 9, 1985,
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by performing a walkdown of accessible portions that included the following
as appropriate:
. System lineup procedures matched plant drawings and the as-built configu-a.
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Equipment conditions were observed for items which might degrade perfor-t mance.
Hangers and supports were operable.
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The interior of breakers, electrical and instrumentation cabinets were inspected for debris, loose material, jumpers, etc.
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Instrumentation was properly valved in and functioning; and had current calibration dates.
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Valves were verified to be in the proper position with power available.
Valve locking mechanisms were checked, where required.
During a field inspection, it was noted that extensive sodium hydroxide buildup had occurred around the QS-4 pump seals and various flanges located in the chemical addition building.
Additionally, various QS line flange leaks in the PAB have resulted in chemical deposits on safety related river water lines. These conditions have existed for several months.
The plant manager informed the inspector that an MWR was issued to repair those valves and flanges that require system isolation (to be accomplished during the next refueling outage).
The inspector had no further questions at this time.
5.
ESF Equipment Status The purpose of this section is to summarize the status of current inspection activities related to identified hardware problems at Beaver Valley, Unit 1.
Ongoing licensee corrective actions, whether involving Engineering, Design Changes and Modifications, or Corrective Maintenance, were reviewed by the inspector through discussions with personnel, document reviews, equipment walkdown, and observation of work in progress as appropriate.
a.
River Water Seal Lines Unresolved Item (84-04-06) was opened to track a concern regarding the seismic qualifications of the RW system seal line pipe hangers.
Since then, it has been determined that the pipe hanger which was mistakenly trimmed by Unit 2 construction personnel, belonged to the turbine plant river water system, a non-category 1 system used to support secondary side components. The seismic calculational methods employed in the original seal line design of the safety related RW system are detailed in Section B.2.1.9, Simplified Seismic Analysis of Small Size Seismic i
Class I Piping (less than 6 inches).
This item is closed.
i The licensee is currently in the process of performing a modification to the safety grade river water seal lines for RW-P-1A, B, C, per Design Change Package 219.
The purpose of this modification is the replacement of carbon steel lines, which have interacted with the river water to form a crud buildup, with stainless steel lines less susceptible to this type of problem.
Discussions with NECU indicated that a more rigorous method, the NUPIPE computer code, was used for the seismic calculations of this modification.
~During August, 1985, the inspector has periodically observed the work being conducted in the field, reviewed the ESF post-maintenance testing, which has included various hydro tests of the seal line and pump perfor-
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mance tests.
The inspector has determined that licensee controls over this activity is satisfactory.
At the conclusion of this inspection, work was still in progress for RW-P-1C.
b.
Station Batteries 3 and 4 - Update IFI (85-17-01):
Review 10 CFR 50.59 evaluation, should DLC decide to replace station batteries No. 3 and 4 while the plant is operating.
Recent discussions with the Plant Manager indicate that licensee does not now intend to replace these batteries as long as the daily checks indicate no further degradation of the end cells; that is, the cell wall crazing does not propagate to a point where a thru wall crack is imminent.
This item is closed.
Unresolved Item (85-17-02): Verify that seismic calculations considered the nonyielding effects of the support frame on the station battery end cells.
Engineering Memorandum 61556 addresses this concern, and its contents were discussed with cognizant representatives of NECU.
The licensee has concluded that:
(1) The racks for both the recently replaced No. I and 2 batteries, as well as the old No. 3 and 4 batteries, should be expanded during the fifth refueling outage (May, 1986) to ensure a 1/4 inch gap at the end supports.
(2) As long as the crazing of the end cells for batteries No. 3 and 4 does not rapidly degrade, these batteries will remain in a stable state able to withstand the effects of a design bases earthquake (about 0.7g).
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The inspector forwarded a copy of these engineering calculations to Re-gion I for an independent review by a specialist.
This item remains open until the rack extensions are complete.
c.
Diesel Generator Air Start System During the diesel generator governor investigation, (see IR 334/85-17),
the inspector noted that one of the compressor isolation valves in the air start system was leaking badly. An operator had already placed a blue tag on this system and initiated an MWR to correct it.
On August 9, 1985, the No. 1 emergency diesel generator was taken out of service to repair it.
The inspector observed ongoing work in the field and noted that operability was proved by starting the diesel and running it for approximately 7 minutes afterwards.
On August 14, 1985, during the monthly surveillance of the diesel gener-ator, when it is loaded for a one hour run, it was noted that one of the four air start motor pinions did not retract from the flywheel upon startup. The diesel generator was shut down and declared out of service.
The inspector observed the licensee replace the air start motor in ques-i
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tion and conduct a retest Of this system per OST 1.36.1.
During this retest, the pinion again did not retract upon diesel startup.
The diesel was only run to about 490 rpm which is-idle speed.
The licensee again
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disabled the diesel generator and determined that a solenoid operated valve (SOV) in the airline upstream of the air start motors had stuck open. This valve was disassembled, cleaned, replaced and the motors retested.
No further problems were noted and the diesel was declared operable.
The inspector noted that the 50V is under the jurisdiction of the I&C Department.
Initial discussions could not determine whether routine preventive maintenance recommendations referenced in the vendor's manual would be added to the PM program.
This is Inspector Follow Item (85-18-05).
Through a control room log review, it was determined that the remaining three air start motors were replaced for the No. I diesel on August 22, 1985.
Maintenance engineers stated that this conservative approach was decided upon to assure diesel start.reliabilty since their pinions failed to retract due to the SOV problem.
This action is satisfactory.
I The ORC Maintenance and Operation Subcommittee Report 85-3 contains an
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open item (85-2/8) involving Incident Report 84-80, Diesel Generator Air Start Motor Failure. They discussed a Morrison-Knudsen Company letter dated July 23, 1985, concerning diesel generator reliability.
It was noted that air filters, strainers and condensate drain valves have'been shown to be only partially effective in preventing moisture-related damage to the internal surfaces of system components and that moisture
present in the starting air remains inside the air start motors causing rust and scale which could prevent correct operation.
The MOS noted that the addition of air dryers is strongly recommended by the NRC in NUREG/
CR-0660, NUREG/CR-2989, and Generic Letter 84-15.
It was recommended that Maintenance consider reactivating DCP-131 for the addition of an air dryer system for the diesel.
Discussions with the Plant Manager' indicated the EM 61618 was issued on i
August 8,1985, in response to the MOS directive.
The EM requests NECU i
to evaluate the entire air start subsystem problems which include the previously mentioned moisture buildup, as well as excessive air compres-sor maintenance, and relief and discharge check valve failures.
A re-
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I sponse was requested by September 9, 1985.
Review of DLC's resolution to this concern is IFI (85-18-06).
d.
Diesel Generator Start Relays From a log review, the inspector determined that on August 22, 1985, the No. 2 diesel generator. failed to manually start upon demand from the
control room during a test.
The second attempt was successful.
The control room start controls send signals to one of two manual start re-
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lays (MSR), depending upon which was selected for preferred start.
This
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is not a safety function, as both the emergency bus undervoltage and safety injection signals go to two fast start relays (FSR). The problem
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with the MSRs is a recurring one and corrective action is being tracked under Unresolved Item (84-22-02).
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j The inspector reviewed a Pittsburgh Testing Laboratory (PTL) report dated
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July 25,1985, prepared for DLC to evaluate a previously failed MSR.
l Tests at PTL failed to duplicate the malfunction.
However, energy dis-l persive X-ray analysis of the particulate matter on the contacts surface,
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indicates a large chloride and sulfide content.
It was thought that the sulfur originated from the atmosphere.
This is not unreasonable because of the proximity to several fossil fuel plants.
l The inspector noted that both the FSR and MSR relays in the control
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cabinet provided by GM's Electro-Motive Division appeared to be similar.
j The EMD maintenance instruction (5434) stated that these relays were of j
similar construction and that the switch assembly contacts are not ex-
pected to corrode or ever require cleaning. A review of the maintenance
history related to these relays was inconclusive because past problems
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with MSRs had not always been captured on an MWR. Discussions with the j
electrical maintenance supervisor indicated that the procurement group i
has initiated an EM to identify an acceptable replacement model.
Unre-l solved Item (84-22-02) remains open pending identification of a qualified j
replacement for both the FSRs and MSRs that meet reliability goals.
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e.
Diesel Generator Governor Start Failure The No. 2 diesel generator failed to start on the first attempt during its monthly surveillance test (OST 1.36.1) on August 26, 1985.
The in-spector observed the second attempt which did start the diesel.
However,
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speed control problems were observed in that a momentary peak speed of
about 700 rpm was achieved before dropping back down to its 490 rpm idle
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setting. The licensee declared it inoperable and complied with the TS action statement. After replacement of the Woodard governor on August 27, 1985, the diesel was retested and returned to service.
From a review of the maintenance history, this appears to be the second time a governor
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has failed.
Review of DLC's action to determine the cause of its failure
is Inspector Follow Item (85-18-07).
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LER 85-14, discussed in detail 8 of this report, noted that prior to the i
governor and manual start failures discussed above, the reliability num-l bers for the last 20 and 100 start demands were 0.95 and 0.90 respec-
tively for the No. 1 diesel, and 0.95 and 0.91 for the No. 2 diesel, i
Continued licensee attention to the items discussed above is necessary l
to assure overall system reliability.
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6.
Status of TMI Action Plan Requirement l
The purpose of this inspection is to evaluate the present status of installed plant equipment or modifications and program / procedure changes to determine, in the inspector's judgement, if the TMI Action Plan Requirements have been
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met, or are in the process of being met, or additional Region I, NRR, or I&E action is required to resolve the issues.
This also includes items that had been previously closed, to determine whether or not subsequent problems have been experienced.
I.A.1 - Shift Technical Advisor The licensee is required to provide an on-shift technical advisor to the shift supervisor.
The STA is required to have a Bachelors Degree or equivalent,
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in a scientific or engineering discipline and have received specific training
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in the response and analysis of the plant for transients and accidents.
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A full time STA is currently assigned to each shift when the plant is operat-ing in Modes 1 thru 4.
This is consistent with TS Table 6.2-1, Minimum Shift Crew Composition, Amendment No. 70. Through discussions with personnel, the
inspector determined that the licensee typically trained an individual for this position for about 18 months prior to shift assignment. This program
contained about 9 months of plant specific system designs, and simulator work.
i Initial NRC inspection of this area can be found in Inspection Reports 80-27 and 81-08.
The inspector notes that the current long term program plans for the STA functions are in a state of flux because the licensee has successfully up-graded their staffing levels for SRO and R0 licensed individuals in prepara-
tion for the startup of Unit 2.
Though several of the current STAS have SRO licenses limited to fuel handling, none hold full SRO licenses at this time.
j Whether the licensee intends to dedicate some of its current staffing re-sources to assure that each licensed shift supervisor or shift manager for the dual units has the equivalent of a four year technical degree is yet to be determined.
The licensee is in full compliance with commitments for this section (Closed).
I.A.1.2 - Shift Supervisor Responsibilities Plant administrative and management procedures were required to be revised as necessary to assure that reactor operations command and control responsi-bilities and authorities are properly defined.
Corporate management was to revise and promptly issue an operations policy directive that emphasizes the duties, responsibilities and lines of command of control room operators, the shift technical advisor and the person responsible for reactor operations command in the control room (senior reactor operator).
At Beaver Valley, those requirements are currently specified in Station Ad-ministrative Procedures, Chapter 4, Plant Operations Group and Chapter 16, Technical Advisory Group, as well as Operating Manual Chapter 1.48, Conduct of Operations.
Since this was initially reviewed in Inspection Report 80-27, the licensee's program has been upgraded considerably as a result of a Sever-ity Level III Violation that occurred during startup from the third refueling
outage (documentation can be found in NRC Inspection Reports 83-19, and 83-23).
A contributing factor in this event was the large number of newly licensed
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personnel that were placed on shift for the first time without a clear under-standing of exactly what was expected of them.
To correct this situation, the Operations Supervisor now conducts personal interviews with each licensed individual prior to shift assignment.
The licensee is currently in full compliance with this section (Closed).
I.A.1.3 - Shift Manning The shift manning requirements of this section contained overtime restrictions to limit an individual to no more than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> straight time with a break of at least 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> between work periods, and no more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7 day period, nor more than 14 consecutive days without having two consecutive days off.
Station Administrative Procedures Chapter 4, contain DLC's policy for working hours of licensed individuals.
This policy deviates slightly from that specified in NUREG-0737 in that an individual is permitted to work up to 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight and an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> break is required between work periods.
This is due in part to previous labor agreements. The inspector notes that in practice, with the large number of licensed individuals currently available, the intent of the overtime restrictions during operations is being met.
Any deviation from the above is required to be authorized by the Plant Manager in accordance with Nuclear Division Directive 19, Use of Overtime.
Minimum shift crew requirements are contained in TS Table 6.2-1 and the inspector routinely verifies licensee compliance in this area (Closed).
I.1.2.1 - Immediate Upgrading of R0 and SRO Training and Qualifications.
Initial NRC inspection of this item is documented in Inspection Report 81-10.
At that time, it was determined that the licensee's program satisfactorily addressed the concerns in NUREG-0737.
The licensee's training program was last reviewed in Inspection Report 83-28.
The adequacy of the licensee's program as demonstrated through NRC administered oral, written and simulator exams for licensed individuals, was last reviewed in Inspection Report 85-10.
The pass rate of personnel taking NRC license exams has consistently been satisfactory.
No program deficiencies are currently open and the licensee is in full compliance with~this requirement (Closed).
I.A.2.3 - Administration of Training Program Pending accreditation of training institutions, the licensee is required to
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assure that instructors who teach systems, integrated responses, transient and simulator courses demonstrate senior reactor operator qualifications and be enrolled in appropriate requalification programs.
Through discussions with licensee personnel during the past year, the inspec-tor has verified that licensee personnel involved in this function have re-ceived SRO instructor certifications.
NRC Inspection Report 84-32 documented
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the results of written and oral examinations that were administered for eight
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instructor certifications among the SRO and RO licensee candidates.
This function is now routinely inspected by Region I.
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Through discussions with Training Department personnel, the inspector deter-
i mined that DLC is in the process of accrediting their training program to the
INPO standards (0 pen).
1.A.3.1 - Revised Scope and Criteria for Licensino Exams.
Simulator examinations are to be included as part of the licensing examination.
t Beaver Valley has just recently completed a plant specific training simulator
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that is used for initial license and requalification training of all applic-
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able personnel.
The use of this simulator has also been reviewed by Region
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I examination personnel as part of the routine NRC administered examination
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j process.
The inspector is aware of no deficiencies in this area (Closed).
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I.C.1 - Short Term Accident and Procedure Review I
Licensees were required to perform analysis for transients and accidents, prepare emergency procedure guidelines, upgrade emergency procedures, includ-i ing those for operating with natural circulation conditions, and to conduct
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operator retraining.
Emergency procedures were required to be consistent with i
the actions necessary to cope with the transient and accident analyzed.
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Since this item was initially examined in NRC Inspection Report 80-27, the
licensee has undertaken considerable efforts to upgrade the emergency operat-ing procedures (EOPs) in conjunction with the recommendations developed by.
i the Westinghouse Owner's Group.
Licensed personnel are currently undergoing lt the required training for the E0Ps.at the Beaver Valley simulator.
The pro-
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cedures are expected to be put into effect by the Fall of 1985.
Inspector j
discussions with the licensing project manager, NRR, indicate that TAC 44282
is currently tracking NRR's final review and acceptance of the proposed E0P i
guidelines. A Region I inspection will be conducted in this area after the i
NRR order is issued (0 pen).
l I.C.2 - Shift and Relief Turnover Procedures.
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Plant procedures were required to be revised as necessary to assure that a l
shift turnover checklist is provided and required to be completed and signed l
by the oncoming and offgoing individuals responsible for command of operations in the control room.
Supplementary checklists and shift logs should also be developed for the entire operations organization.
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l The inspector reviewed the current station practices in this area.
The shift i
turnover checklist requires the oncoming operator to review the control board status, equipment status, and tests and maintenance items in progress as well as ESF equipment status prior to conducting turnover discussions with the in-
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dividual being relieved.
Then, both the oncoming and offgoing personnel
jointly review the control boards'together to identify any off-normal condi-
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tions.
This type of checklist is used for both the shift supervisor, shift i
foreman, and two licensed reactor operators. Additionally, the shift techni-l cal advisor performs OST 1.48.3, Control Board Checklist, to independently l
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a verify the correct alignment of' essential ESF equipment. The shift and relief i
turnover procedure that resulted from the Severity Level III violation docu-
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mented in NRC Inspection Reports 83-19 and 83-23 is considered to be unusually
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complete and thorough. The licensee is in full compliance with this require-
ment (Closed).
I.C.3 - Shift Supervisor Responsibility This item is similar to I.A.1.2 discussed above. The licensee's administra-tive procedures currently define the responsibilities and authority of the reactor operator and senior reactor operator's functions.
Through routine
discussions with plant personnel on duty during various operational transients that have occurred in the past year, the inspector has verified that these responsibilities are adequately understood and carried out (Closed).
I.C.4 - Control Room Access Emergency procedures were required to be reviewed and revised as necessary
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to assure that access to the control room under normal and accident conditions
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is limited to those persons necessary to the safe command and control.of operation.
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Initial inspection of this item is captured in Inspection Report 80-27. Proper implementation of these requirements for accident conditions has been verified i
by NRC team inspection of the Emergency Preparedness Drills (See Inspection i
Report 84-16).
This includas staffing of the Technical Support Center and the Emergency Support Center per the Station's Approved Emergency Preparedness
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Plan. Cor, trol Room access during normal conditions is left to the discretion of the shift supervisor as long as operational activities remain unaffected.
The licensee's performance.in this area has been cyclical with the low point
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being reached during outages and recoveries from outage conditions.
Control i
room access was considered one of the contributing factors to the events that led to the Civil Penalty as documented in NRC Inspection Report 85-03.
Since i
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that time, the inspector has verified that control room access levels are ac-
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ceptable during normal plant operations.
Followup on implementation of these i
access controls during the next refueling outage will receive further atten-tion as part of the routine resident inspection program (0 pen).
I.C.5 - Feedback of Operatina Experience Initial licensee action to assure that operating'information pertinent to i
plant safety originating both within and outside the utility organization is i
continually supplied to operators and other personnel and is incorporated into i
training and retraining programs, was reviewed in NRC Inspection Report 81-08.
i The inspector has routinely verified that such informattun originating from outside of Duquesne Light is routinely processed through the Licensing and i
Compliance Group for dissemination and verification of any necessary actions.
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The licensee's incident reporting system is routinely used as a vehicle to
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identify root causes of operating events and assure that proper corrective l
actions are identified to all personnel.
Additionally, significant operating
events at Beaver Valley and other plants are routinely factored into the re-
training program, which is inspected by Region I (Cicsed).
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I.C.6 - Verify Correct Performance of Operatina Activities
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Since'this item was initially reviewed in NRC Inspection Report 81-08, the lt licensee has put into effect an extensive double verification program that l
encompasses all critical operational activities, surveillance procedLres, test j
procedures, temporary procedures, maintenance and equipment clearance activi-
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ties.
The inspector has determined that licensee actions in this area have
been extensive and comprehensive resulting in~ satisfactory compliance.
This
item is reviewed on a routine basis by the inspector and no problem associated l
with it is currently outstanding (Closed).
I.D.1 - Control Room Desian Reviews
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Responsibilities regarding close out of this item have been assigned to'NRC Region I (0 pen).
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I.D.2-- Plant Safety Parameter Display System (SPDS) Console
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An SPDS has been installed and is being debugged at this time.
The licensee's i
commitment contained in the NRR order of June 12,.1984, calls for the SPDS
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to be fully functional by the end of the fifth refueling outage, scheduled i
for mid-1986.
Discussions with licensee personnel indicated that they are j
currently ahead of schedule and plan on making the SPDS fully functional in conjunction with the changeover for the new symptom oriented emergency oper-
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j ating procedures, scheduled for the Fall of 1985 (0 pen).
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II.B.1 - Reactor Coolant System Vents
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NRR closed out the technical review of the acceptability of this item in a letter to DLC dated September 8,1963.. Resident inspector observation of the
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functional test is documented in Inspection Report 84-08. Modification work j~
is complete and all emergency operating procedures have been updated, with operator training complete. The licensee is in full compliance with this item (Closed).
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j II.B.2 - Design Review of Plant Shieldina and Environmental Qualifications
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of Equipment for Spaces / Systems which may be used in Post-Accident Operation i
The plant shielding review was documented in Regional specialist IR 82-24.
The post-implementation review verified licensee compliance in this area, l
and the inspector is aware of no changes to the installed shielding.
Radiation qualification of safety-related equipment is currently an open
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A generic issue that is being reviewed as part of the 10 CFR 50.49 requirements.
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The inspector believes all required equipment modifications are complete as
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of ' January, 1985.
An NRC team inspection is still pending'for this functional l
area (0 pen).
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II.B.3 - Post-Accident Sampling System (PASS)
The licensee installed their PASS system which was initially reviewed in IR 80-27. A detailed post-implementation review was performed by Regional specialists as documented in IR 84-21.
At that time, 11 open items were identified that required extensive effort on the licensee's part to close out.
These items remain open at this time pending Region I specialist review.
In-spector discussions with licensee personnel indicated that appropriate people have been trained in the use of this system and that to their belief, all work resulting from the 11 open items have been complete at this time, and the system is fully operational (0 pen).
II.B.4 - Training for Mitigation of Core Damage
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s Initial inspection was performed and documented in IR 81-18, and the licensee was considered in compliance at that time.
The inspectors had previously re-viewed the contents of the licensee's text book in this area and found it to be acceptable.
Additionally, routine NRC licensing examinations have identi-fied no problems gv..eric to the DLC training program.
The licensee is in full compliance with this requirement (Closed).
II.D.1 - Relief and Safety Valve Test Requirements Licensees were required to conduct tests to qualify the reactor coolant system relief and safety valves under expected operating conditions for design bases transients and accidents. The licensee's initial submittal was made to NRR on July 1, 1982, detailing their participation in the Electric Power Research Institute generic valve test program and the Westinghouse Electric Corpora-tion's specific work being done for Beaver Valley in this area.
Additional information was provided in a DLC letter to NRR dated June 24, 1983, as well as DLC's response to requests for additional information dated Octo-ber 4, 1984, and January 10, 1985.
As of this inspection report, NRR has not issued a safety evaluation report and this item remains open on a generic basis pending their; review and close out (Open).
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II.D.3 - Valve Position Indication The reactor coolant system relief and safety valves are required to be pro-vided with a positive indication in the control room derived from reliable valve position detection devices for indication of flow to the discharge pipe.
l NRC IR 80-27. documented the initial review in this area. The licensee now l
employs an individual acoustic monitor for each of the three PORVs ard safety l
valves in addition to tail pipe thermocouples.
Routine resident inspection has identified no known problems with this system.
It is functional at this time and the licensee is in compliance (Closed).
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i II.D.1 - Auxiliary Feedwater System Evaluation (1) that the design provided for auto-The licensee was required to verify:
matic initiation in the AFWS, (2) that the initiation signals and circuits 9-are designed so that a single failure will not result in the loss of function, (3) that test ability of the initiation signals and circuits are a feature t-of the design, (4) that the signals and circuits are powered from the emer-1.
gency buses, (5) that manual capability to initiate the AFWS in the control room is retained such that a single failure in the manual circuit will not t
result in loss of the system function, (6) that the AC motor driven pumps and valves are included in automatic actuation of the load onto emergency buses, and (7) that the automatic initiation and circuits are designed so that fail-ure will not result in the loss of manual capability to initiate 1,t from the control room.
e This item was initially reviewed in IR 82-08, which tracked modification work Since then, the only AFW modification involved a one-for-one e
under DCP 299.
The inspector has verified system changeout of the flow control valves.
operability through several routine ESF walkdowns in the past two years.
en I
Discussions with the NRR licensing project manager indicated that no long term Therefore, the licensee system modifications are required from Beaver Valley.
is in full compliance with this item (Closed).
II.E.3.1 - Emergency Power for Pressurizer Heaters Licensees were required to upgrade the power supply for the pressurizer s
heaters such that either the offsite power source or emergency power source is available to a pre-determined number of heaters and associated controls necessary to establish and maintain natural circulation at hot standby con-ditions.
These requirements-are cur-This item was originally reviewed in IR 80-27.
rently captured in Beaver Valley TS 3.4.4, Amendment No. 39, which requires at least 150 KW of pressurizer heaters with a steam bubble when the plant is Currently, the Group A and D heaters are supplied from in Modes 1 thru 3.
the DF emergency bus while the Group B and E heaters are supplied from the Any one heater group exceeds the minimum load requirements.
AE emergency bus.
The licensee continues to remain in full compliance with this requirement (Closed).
II.E.4.1
. Dedicated Hydrogen Penetration External recombiners or purge systems for post-accident combustible gas con-trol of the containment atmosphere are required to provide containment pene-tration systems that are dedicated to that service only and that meet the re-dundancy and single f ailure requirements.
Since that time, the lic-This item was reviewed ~in NRC IR 80-27 and 82-01.
ensee aas made no other modifications to the system that degra original commitments.
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II.E.4.2 - Containment Isolation Dependability Implementation of the diverse isolation functions was reviewed in IR 80-27.
Review of the containment pressure setpoint and purge and vent isolation sig-nal is contained in IR 82-01.
Since Beaver Valley employs a subatmospheric containment, the purge and vent valves are requirRd to be closed when operat-ing in Modes 1 thru 4.
Hence, the concern in subsection 6 is not applicable.
NRR review contained in a letter dated December 11, 1981, concluded that the containment isolation setpoint meets the criterion of NUREG-0737 and the ad-ditional limiting guidelines provided by the staff (Closed).
II.F.1 - Accident Monitoring
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The noble gas monitor, iodine particulate sampling and containment high range monitor review is the responsibility of Region I and has been previously looked at in NRC IR 80-27 and 82-24.
Outstanding items associated with these inspection reports have since been satisfactorily closed out.
Likewise, the containment pressure water level and hydrogen concentration monitors have been reviewed in IR 82-24.
The licensee has routinely verified operability during control room tours.
The instruments are routinely calibrated and referenced by plant procedures. The licensee is in full compliance with this -item (Closed).
II.F.2 - Instrumentation Protection of Inadequate Core Cooling This item required licensees to provide additional instrumentation or controls where necessary to supplement existing plant equipment in order to provide unambigious, easy to interpret indication of inadequate core cooling.
In-cluded were requirements for the primary coolant saturation monitors, reactor water level indication and core exit thermocouples.
The current Beaver Valley system configuration includes a subcooling monitor with inputs from both the RTD manifold and core exit TCs, a Westinghouse supplied reactor vessel level indication system (RVLIS) and existing plant core exit TCs.
These systems are currently in place and operable. Though the operations personnel have received training in these design changes, the
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current Emergency Operating Procedures do not refer to or make use of this equipment.
Through discussions with operations personnel, the inspector was informed that the new upgraded symptomatic emergency operating procedures scheduled to be implemented in the Fall of 1985 will refer to these various information systems.
Per DLC letter of April 24, 1984, which addressed the ICC instrumentation system concern of Generic Letter 82-28, the licensee has committed to upgrad-ing to a single unit, all of the various functions previously discussed.
The reason for this is that the new unit will be a class 1E safety grade system whereas the previous systems were not.
The licensee expects this to be fully functional and in place by late 1987.
Review of the adequacy of this design is currently being tracked by NRR (0 pen).
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I II.G.1 - Power Supplies for Pressurizer Relief Valves Block Valves, and Level Indicators i
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Motor and control components of the PORVs and associated block valves were required to be capable of being supplied from either the offsite power source i
or the emergency power source, with the connections to the emergency buses through devices that have been qualified in accordance with safety grade re-
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quirements.
Additionally, the pressurizer level indication instrument chan-nels shall be powered from the vital instrument buses, j
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i The original inspection of this item is documented in IR 80-27.
Beaver Valley currently has three PORV. lines that include associated block valves.
Two are supplied from one emergency bus and the third is supplied,from the second.
i Each emergency bus is capable of being supplied from an offsite electrical source as well as an emergency diesel generator.
Each of the three pressur-
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izer level indicators are supplied from a separate vital bus.
The licensee
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remains in full compliance with this requirement (Closed).
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II.K.1 - IE Bulletins l'
The original bulletin (79-06, A, Rev. 1) has been reviewed and closed out in
IR 79-16.
This bulletin addresses the review of operational errors and system i
misalignments identified during the Three Mile Island incident.
Since that i
time, Beaver Valley has developed an extensive and thorough administrative i
control system to assure the correct system alignment when starting up from
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a refueling outage, recovering from an unanticipated shutdown, and returning
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systems to normal after maintenance, modification or testing, that has re-
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ceived extensive NRC review.
Through daily reviews of plant activities, the i
inspector has verified that~the licensee's administrative controls in this
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area have not been downgraded and that performance is as expected.
The lic-j ensee is in full compliance with these requirements. This item is similar to I.C.6, discussed above (Closed).
i II.K.3.1 - Automatic PORV Isolation and II.K.3.2 - Report on PORV's for Beaver Valley Unit 1
.
The NRR safety evaluation report of September 14, 1985, determined that the
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existing PORV, safety valve and reactor high pressure trip setpoint are ac-i captable and that an automatic PORV isolation system is not required. There-
fore, no additional actions are required in this area (Closed).
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II.K.3.3 - Reporting Safety Valve and Relief Valve Failures and Challences TS 6.9.1.5, Amendment No. 74, requires documentation of all challenges to the pressurizer power operated relief valves or pressurizer safety valves and re-porting of such on.an annual basis.
To date, the licensee has had no chal--
lenges since the amendment werit into effect (Closed).
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II.K.3.5 - Automatic Trip of Reactor Coolant Pumps Through discussions with the licensing project manager, the inspector was in-formed that this item has been generically closed by NRR and that a safety evaluation report would be forthcoming.
Beaver Valley, Unit 1 is not going to be required to make any further changes in this area.
NRR is tracking this item (Closed).
II.K.3.9 - Proportional-Integral-Derivative Controller Modifications IR 81-20.previously discussed this item and identified that two out of three PORVs at Beaver Valley had a derivative action in their respective control circuits.
The action plan item required deletion of this feature from the circuitry. The inspector at that time, had determined that loop calibration procedures Nos. LCP-6-P445 and 444, Pressurizer Pressure Control of Loop Calibrations, included instructions for setting the rate signal potentiometer to 6 seconds in lieu of zero as required by the NUREG items. At that time, a jumper and lifted lead tag No. 2632 was posted to ensure that the switch was not reset prior to correction of the existing procedures (Closed).
II.K.3.10 - Proposed Anticipatory Trip Modifications NRR reviewed this issue as part of TS Amendment No. 62 and determined that the anticipatory trip modification would not be required of Beaver Valley.
This item was forwarded to Duquesne Light in a letter dated January 26, 1983 (Closed).
II.K.3.25 - Integrity of RCP Seals NRR reviewed this issue and determined that the licensee adequately demon-strated that the integrity of the BV reactor coolant pump seals is maintained during a loss of offsite power event. This is documented in the NRR letter of June 24, 1982.
No further action was required of DLC.
NOTE: The remaining' items of II.K.3 not discussed in this detail have been determined to be not applicable to the design of the Beaver Valley, 3 loop Westinghouse pressurized water reactor plant (Closed).
III.A.1.1 - Emergency Preparedness, Short Term l
Previous NRC team inspections of the annual emergency preparedness plan docu-mented in recent NRC IR 83-03, 83-15, 84-03, 84-16, have identified no ongoing weaknesses in this area. The past SALP evaluations of emergency preparedness l
have rated Beaver Valley as Category 1 for their excellent ongoing performance (Closed).
III.A.1.2 - Upgrade Emergency Support Facility l
- The licensee has committed a large amount of resources to upgrade their emer-gency response facility which contains the technical support center and emer-gency operation facility. NRC Region I is currently scheduled to " play" in i
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the next BV EPP drill scheduled for September, 1985, and will use these facilities to observe the licensee's personnel operating from them as neces-sary to demonstrate adequate implementation of the emergency plan.
Because the technical support center is located in the ERF which is more than 2 minutes walking distance from the control room, the acceptability of this item is still open pending final review.
A Region I close out inspection will be scheduled after the SPDS becomes fully operational (0 pen).
III. A.2 - Improving Licensee Emergency Preparedness - i.ong Tern Review and close out of this item is the responsibility of Region I.
The in-spector is aware of no deficiencies, open items or problems in this area at this time (0 pen).
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III.D.1.1 - Primary Coolant Outside Containment This item required the licensees to develop a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident. The initial NRC review of the BV leak reduction program was contained in IR 80-27.
The licensee's ongoing efforts in this area have resulted in the lowest liquid waste volume level in the plant's history.
The inspector is aware of no problems in this area that could result in potential release paths to the primary auxiliary building (Closed).
III.D.3.3 - Inplant Radiation Monitors This item was initially reviewed in IR 80-20 with the remaining outstanding concerns closed out in IR 81-10. Since then, routine Region I based Health Physics Specialists have reviewed the licensee's program in this area and have identif.ied no further concerns (Closed).
III.D.3.4 - Control Room Habitability This item required licensees to assure that control room operators will be adequately protected against the effects of accidental release of toxic and radioactive gases and that the plant can be safety operated or shut down under design based accident conditions.
NRC IR 83-21 reviewed the hardware changes and determined that the systems were operating as specified in the TS.
NRR reviewed the licensee's system and determined that the design was acceptable per letter of February 9, 1982.
The only item of possible concern in this area is when the masonry wall separating the Unit 1 and Unit 2 control rooms is removed.
At that time, the control room pressurization system will have to be evaluated and tested to assure that the habitability systems are able to perform as specified in TS 4.7.7.1.
DCP 611 is currently under development to address this item-(Closed).
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l 7.
Updated Final Safety Analysis Report Assumptions The inspector reviewed Section 14.1, Core and Coolant Boundary Protection
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Analysis, to determine whether referenced system performance criteria, para-meter band widths and procedures assumed within, were reflected in the BV j
Technical Specifications and Operating Procedures, as appropriate. The fol-
lowing specific items were identified:
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FSAR Section 14.1.3, Rod Cluster Control Assembly Misalignment, indicates
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that for conditions where one or more rod position indicator channels are out of service, detailed operating instructions shall be followed to assure the alignment of the non-indicated assembly. These instruc-tions require selected pairs of core exit thermocouples to be monitored in a prescribed, timed sequence and following significant motion of a non-indicated assembly.
Review of DM Chapter 1.538.4, Abnormal Operating Procedure for RPI Malfunction, and OM Chapter 1.1.4.L Correcting Safety-Related Alarms Conditions, indicates that the core exit TC sequence has not been developed and incorporated into appropriate procedures.
This is not an immediate problem as the reactor is operated at full power with all rods out and the automatic control system in manual.
Few RPI mal-functions are noted in this condition. However, the licensee intends to use the rod control system in the automatic mode for the next cycle, and the above inconsistency needs correction beforehand.
The FSAR notes on page 14.1-8 that misaligned rod cluster control assen-
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blies are detected by the power range negative rate trip. The purpose of this trip is to avoid exceeding core peaking factors for a dropped rod with the rod control system in auto. This item needs clarification.
FSAR Section 14.1.4, Uncontrolled Boron Dilution, assumes that the high
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source range flux level and all reactor trip alarms are effective for any dilution during startup from approximately 2,000 ppe. Table 3.3-1
of the TS allows one source range monitor to be out of service while in Modes 2 thru 5.
The action statement only requires restoration of the inoperable channel to the operable status prior to increasing thermal
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power above the P-6 setpoint.
This appears to be an inconsistency in that the redundant SRM alarm is allowed to be inoperable.
The inspector also identified other inconsistencies that were discussed with the licensee.
It was determined that DLC had already independently identified them during a review of all sections of Chapter 14. The licensee stated that
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their review was being undertaken to prepare an FSAR/TS natrix of the various
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assumptions referenced in the FSAR, in order to upgrade the quality of the design change and modification review p wcess required by 10 CFR 50.59.
The inspector will continue to review these items, to assure timely correction, as IFI (85-18-08).
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8.
Inoffice Review of Licensee Event Reports (LERs)
The inspector reviewed LERs submitted to the NRC:RI office to verify that the
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details of the event were clearly reported, including the accuracy of the description of cause and adequacy of corrective action. The inspector deter-mined whether further information was required from the _ licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed:
LER: 85-13 Reactor Trip due to Low-Low Steam Generator Level LER: 85-14 Inaoility of Diesel Generator to Assume Full Load.
These events were discussed at length in NRC Inspection Report 334/85-17.
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Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings.
A summary of inspection findings was further discussed with the licensee at the conclusion of the report period.