IR 05000219/1990016
| ML20058A837 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 10/18/1990 |
| From: | Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058A827 | List: |
| References | |
| 50-219-90-16, NUDOCS 9010290231 | |
| Download: ML20058A837 (27) | |
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a V. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-219/90-16 Docket No, 50-219 License No.
.OPR-16 Licensee:
GPU Nuclear Corporation i Upper Pond Road Parsippany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station Inspection Conducted: August 23, 1990, - September 22, 1990 Inspectors:
M. Banerjee, Resident Inspector E. Collins, Senior Resident Inspector
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fO Approved By:
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C Ruland, Chief, Date Reactor Projects Section 4B Inspection Summary:
Inspection Report No. 50-219/90-16 for August 23, 1990 - September 22,-1990
. Areas Inspected:
The inspection consisted of 175 hours0.00203 days <br />0.0486 hours <br />2.893519e-4 weeks <br />6.65875e-5 months <br /> of direct inspection.
The areas inspected-included observation of plant. activities and review of operational events, operation of the turbine building ventilation system,
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walkdown of the ' emergency diesel fuel oil transfer system (section 1.0); review of a plant configuration ' leading to an unmonitored release.(section 2.0);
observation of maintenance activities and surveillance tests-(section 3.0);
review of licensee actions regarding relief valves (section 4.1);
review of licensee actions regarding Core Spray pipe support damage and condensate' pump
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degradation (sections 6.1 and 6.2).
Results: Overall, the plant was operated in a safe manner. A violation of a.
l station _ procedure is identified in this report.
This consists of operating-the-turbine building with-a positive ambient pressure. An unresolved item related to plant configuration control is opened and five previously identified-unresolved items are closed.
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9010290231 9o1o3g gDR ADOCK 05000219 PDC m
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TABLE OF CONTENTS P,. age I.
Executive Summary.
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II. Details.............................
1.0 Ope rations (71707, 93702)*,..................
I 1.1 Review of Operational Events (93702)............
I 1.2 Turbine Building HVAC System (71707,93702).........
1 1.3 Emergency Diesel Generator Fuel Oil System (71710).....
1.4 Control Room Tours (71707).................
1. 5 Fa ci l i ty Tou r s ( 71707)...................
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2.0 Radiological Controls (71707)..................
2.1 Unmonitored Release Paths
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3.0 Maintenance / Surveillance (61726, 62703)......,......
3.1 Installation of Temoorary Shielding
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3.2 Monthly Surveillance Observation........-......
4.0 Engineering and Technical Support (71707,93702)
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4.1 Core Spray Relief. Valves..................-
5.0 Observation of Physical Security (71707)............
6.0 Safety Assessment / Quality Verification (30702,35502,93702)...
6.1 Core Spray System II Seismic Restraint Oamage 11-
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6.2 Condensate Pump Impeller Degradation............
7.0 Review of Previously Opened Inspection Findings (92701)~....
8.0 Verification of Safety Issue Management System (SIMS) Items (TI 2515/065)
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9.0 Inspection Hour Summary:
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10.0 Exit. Meeting and Unresolved Items (30703)............
10.1 Preliminary Inspection Findings
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'10.2 Attendance at Management Meetings conducted by o
Region Based Inspectors
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l'.3 Unresolved Items......................
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- Numbers' identify the NRC inspection procedure use +
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
EXECUTIVE SUMMARY Report No.
50-219/90-16 Operations Overall the plant was operated in a safe manner. The plant was at full power throughout the inspection period except for power reductions of short duration for main condenser backwash or maintenance.
Plant operations when safety systems were not operable were executed safely, were in accordance with the license, and were reported as required.
The plant was operating with a positive ambient pressure in the turbine building in violation of procedure requirements.
This positive pressure contributed to an unmonitored release through a roof vent.
The li ensee is reviewing the turbine building vertilation system design and operating procedure for corrective actions.
During NRC. inspector plant tours, several questionable plant configurations were identified. These conditions show a weakness in plant configuration control. This weakness has been identified in previous NRC inspection findings.
The licensee is currently reviewing these items.
This item was left unresolved.
On 8/25/90 the reactor power was reduced to 50% to facilitate cleaning of the south half of the "C" condenser..The plant was returned to full power on 8/27/90. This evolution was well coordinated and controlled.
Radiological Controls An unmonitored release path was-identified by the licensee on the turbine building northwest roof. This release path was. believed to be in existence for approximately'two years, although the exact time is not known.
Inspection reported in Report 50-219/90-13 evaluated the offsite radiological-consequences-and concluded no there was no hazard to the public.
Maintenance / Surveillance The control room operators were involved and alert during performance of the Isolation Condenser Isolation Test by the Instrumentation and Controls personnel. No other significant observations were made.
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Executive Summary
Oyster Creek Nuclear
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Generating Station Engineering and Technical Supgort, Emergency Planning, and Security
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No significant observations were made in these areas.
Safety Assessment / Quality Verification The licensee identified a damaged snubber and a strut that pulled away from the mounting surface in Core Spray system II, The licensee replaced the damaged snubber and performed a seismic analysis to evaluate the effect of the damaged strut. The licensee appropriately reviewed the impact of these deficiencies on the operability of the system.
Because of this and similar support damage identified in the past, the' licensee has developed a plan to identify the root cause. This review was in progress at the end of the inspection period.
The damaged strut was identified by the Manager of Radwaste Operations while he was performing a back shift tour. The location of the strut was in an area that was previously controlled as a locked high radiation and contaminated area, Recent recovery efforts restored this area to normal access, and contributed
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positively to the identification of this deficiency.
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DETAILS 1.0 Operations 1.1 Review of Operational Events The inspection period began and ended with the reactor at full power.
l Inspectors reviewed key operational events that occurred during the report
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period as discussed in the following paragraphs.
On August 25, 1990, reactor power was reduced to about 50% to enable i
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cleaning of the "C" south condenser to address deteriorating vacuum.
The licensee removed silt from the circulating water line and condenser tubes.
l The "C" condenser vacuum improved after cleaning.
The plant was returned to full power on August 27, 1990. This evolution was executed without significant problems showing good planning and control.
L On August 28, 1990, the licensee identified that the plant computer system l:
was not updating the monitors in the Control Room, including the safety parameter display system (SPDS). This condition was immediately corrected l
by forcing transfer to the back-up computer. The licensee reported this I
condition to the NRC as a major loss of emergency assessment capability l
per 10 CFR 50.72 (b)(1)(v). The computer was found in an infinite loop L
and was not allowing programs of ' lower priority to be executed.
This reporting was conservative since the control room indicators and alarms remained operable during the event. The licensee is currently reviewing
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the need for system improvements. The inspector did not have any further questions.
On August 29, the licensee identified premature lifting of Core _ Spray relief. valve V-20-24 during routine surveillance testing. The system was declared inoperable at' 6:20 p.m. (7 day Technical Specification action statement). At 8:20 p.m. Core Spray system II was isolated for mainte-
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nance to replace the valve and the associated Automatic Depressurization System (ADS) logic (one of two) was declared inoperable'because its permissive input from Core Spray was removed. Inspection Report 50-219/ -
89-06/09 discusses the Core Spray / ADS logic relationship. Technical Specification Table 3.1.1 requires both logics to be operable or tripped.
The licensee began a reactor shutdown for a condition outside of plant technical specifications (Section 3.0.A).
After the relief valve was-replaced,' Core Spray and ADS were declared operable and plant shutdown l:
was. terminated on August 30 at 6:50 a.m., with reactor power at 66%. The-i.<
plant was returned to full power at 11:50 a.m.
Licensee response to this event was proper and the plant was operated'in accordance with Technical Specifications.
The required notification per 10 CFR 50.72(b)(1)(A) was made.. Inspector review of relief valve premature lifting is described in section 4.1'.
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'On September 5, the licensee removed Containment System II from service to clean the heat exchangers because of slowly increasing differential pressure. Also during this system outage, the licensee implemented a modification to motor operated valves (V-21-1, 3, 5,13, and 15) to separate the opening torque switch bypass limit switch from the valve position indication limit switches (Inspection Report 50-219/90-12).
The system was returned to service on September 9.
Inspectors observed portions of the cleaning.
Silt and mud were removed from the heat exchangers. The inspectors had no significant observations.
1.2 Turbine Building HVAC System During review of the unmonitored release (August 22,1990), discussed in paragraph 2.1 of this report, NRC inspectors observed the turbine building north mezzanine air pressure to be positive with respect to the atmosphere.
This positive pressure forced radioactive steam into the atmosphere once a path was available. As a result, inspectors reviewed the operation of the turbine. building HVAC system.
The turbine building HVAC system was modified (early 1980's) to provide radioactive gas effluent monitoring to ensure compliance with regulatory requirements.
The operating deck is served by two supply fans and one exhaust fan, EF 1-33.
The exhaust fan discharges into the atmosphere through the turbine building stack which is monitored for radioactive release.; In addition, air from the operating floor is directed to the condenser bay area via floor openings. The' condenser bay area is supplied by separate fans and exhausts-through the main plant stack. Air is directed onto the operating floor from the south side of the turbine building basement and mezzanine floors.
.The updated FSAR for Oyster Creek, Section 7.4.3.3, indicates that uncontrolled air flow (potentially contaminated) from the turbine building
.to the atmosphere is~ prevented by maintaining the building at slightly below' atmosphere pressure so that any leakage will be in-rather than out.
Negative pressure is created by the^ exhaust fans and regulated by position-ing-of the inlet dampers of these fans.
In Section 9.4.3.2, the FSAR
' describes the system design and controls for maintaining a negative pressure in the operating floor and other areas of the turbine building, including a negative 0.25 inches water gauge-(w.g.) for the condenser area and heater bay. The inspectors questioned if'the existing design for the HVAC system satisfies the description in the updated FSAR.
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Station Procedure-328, Rev 14," Turbine Building Heating and Ventilation
System", requires the operating floor to be maintained at'a negative 0.1-inch w.g. 'when' EF 1-33 is operating or at zero inches w.g. if EF 1-33 is not operating, as read at DPI-389. Additionally,'the condenser and heater-bay: areas are maintained at negative 0.25 inches w.g.
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On August 25, 1990, the licensee opened a roll up door on the turbine operating floor to alleviate high temperatures in the condenser bay area.
Inspectors questioned the control of this evolution and the desirability of this condition considering the potential for unmonitored releases.
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On August 27, 28 and 30, 1990, NRC inspectors observed the turbine operating
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floor had a positive ambient pressure as indicated by differential pressure gauge DPI-389 (pegged below zero) and by air exiting the building through access doors. The equipment operator (EO) who accompanied the inspector during one tour, indicated this reading would probably be entered as zero p
in the E0's tour sheet due to lack of a graduated scale below zero. Also, the DP gauge's calibration had expired.
The-turbine building north and south mezzanines also were positive in pressure with respect to the atmos-phere as indicated by air exiting through access doors. The turbine building operating floor exhaust fan, EF 1-33, had been removed from service for maintenance on August 22, 1990.
Inspectors questioned if the turbine building HVAC system was performing its intended design function.
- The licensee initiated a deviation report to review the turbine building HVAC system operating and design parameters. This review indicated the operating ~ floor of the turbine butiding-is designed to be maintained at atmospheric (0 inch water. gauge) pressure. This conclusion is consistent with the system flow diagram.
This design allows for a flow of air from the operating floor into the negative pressure condenser bay area. Air flow is designed to be from clean to contaminated areas. Additionally, the licensee indicated the turbine building HVAC system does not automatically maintain system balance and requires manual balancing.
Comprehensive instrumentation to monitor building pressure does not exist. The control
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roomLindication for-a turbine building exhaust differential pressure gauge
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as described in the FSAR does not exist. The licensee intends to change the FSAR to reflect the correct plant design.
r To determine the actual safety significance of opening the turbine building roll up door, inspectors reviewed the readings of a continuous atmosphere monitor (CAM) placed at the opening and for one that sampled
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the condenser. bay atmosphere. The CAM measures radioactive particulates and iodine levels.. Given the low readings of the CAM and normal ' radiation levels ~in the turbine building,=the inspector concluded there was no unmonitored release through the open roll up door.
Dyster Creek technical specifications contain requirements on radioactive effluent and monitoring _ instrumentation to assure that radioactive material is not released to the environment in an uncontrolled manner and to assure that the radioactive concentration of any material released is kept as low
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I Also, Oyster Creek technical specification 6.8.1 requires that written procedures be established, implemented and maintained that meet or exceed the requirements of NRC Regulatory Guide 1.33.
Regulatory Guide 1.33, Rev. 2, endorses ANSI N18.7-1976, Section 5.2.2, which requires that procedures be followed.
Station Procedure 328, Rev 14," Turbine Building Heating and Ventilation System", requires the operating floor to be
maintained at zero inches w.g. if EF 1-33 is not operating, as read at DPI-389.
The operation of the turbine building HVAC system such that the turbine operating floor became pressurized above zero inches w.g. when EF i
1-33 was not operating is a violation. (50-219/90-16-01)
1.3 Emergency Diesel Generator Fuel Oil System The inspector reviewed the emergency diesel generator fuel oil system design and operation to verify the operational status of the system.
i Station Procedure 341, Rev. 29, " Emergency Diesel Generator Operation,"
system lineup and Station Procedure 327.1, Rev. 7, " Main Fuel Oil Tank
Receipt Procedure," were reviewed against Process and Instrumentation
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Diagram (P&ID) 3D-862-21-1000, Rev (5). The inspector walked down the system to verify proper valve and electrical component position, labelling i
of components, and acceptable equipment condition.
The general house-keeping in the area, including storage of flammable material and ignition sources and. freeze protection of equipment and piping were inspected, i
Discrepancies included a wrong label on the boiler house fuel oil transfer
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pump suction valve, missing label on the fuel oil tank drain valve, and the label on #1 EDG fuel filter suction pressure indicator that did not match the P&ID. The licensee is currently implementing an improved labelling program throughout the plant.
Improved labels are being
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prepared for the diesel generators.
Also discussed with the licensee were missing components in the checklist for equipment lineup. The diesel generator auxiliary power breakers and the key-lock switch (#1 EDG) for testing the day tank level control. system
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were not-included in the equipment lineup. checklist.
The positioning of the auxiliary power breaker is indirectly. verified by verifying that the immersion heaters, the lubricating-oil circulating pump, and the AC turbo oil pump are energized. An alarm is generated in the control room if the key-lock switch is not in the. " normal" position. These indirect verifica-c tions of component status minimize the' safety significance of this discrepancy.
The level gauge for the No. I diesel-generator day tank was indicated as broken by a deficiency tag attached to the tank.
The tag was not dated.
Alarm response Procedure 2000-RAP-3024.02, Rev. 14, " Electrical Annunciator Response Procedure," for alarm window T-7-6, "EDG 1 Day Tank Level
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Hi/Lo/ Lube Oil Fail," requires the operator to check fuel' level in the day tank for high or low conditions. The inspector asked the licensee
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if any compensatory action was needed, given that the day tank level gauge was broken. The licensee indicated the level gauge was actually functional and the deficiency tag was removed.
The licensee has undertaken a project to improve housekeeping and equipment conditions.
Leaks of fuel and lube oil have been identified and a plan to correct these during the next (13R) refueling outage is being prepared.
The floor grading has been corrected to assure proper drainage of rain water. The concrete surface of the building is also being painted.
The inspector considers the identified deficiencies as minor and do not affect the operability of the fuel oil system. They are being addressed by the licensee. The inspectors concluded the fuel oil system is able to perform its design function.
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1,4 Control Room Tours The inspectors conducted routine tours of the control room.
The inspectors reviewed:
Control Room and Group Shift Supervisor's Logs;
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Technical Specification Log; l
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Control Room and Shif t Supervisor's Turnover Check Lists;
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Reactor Building and Turbine Building Tour Sheets;
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Standing Orders; and,
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Operational Memos _and Directives, j
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No significant observations were made.
1.5 Facility Tours l
The inspectors conducted routine plant tours to assess equipment conditions, personnel safety hazards, procedural adherence and compliance with regula-
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tory requirements.
The following areas were inspected:
Turbine Building.
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t Vital Switchgear Rooms
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Cable' Spreading Room
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Plant configuration control deficiencies are discussed in Section 2.1.
The following additional items were observed or verified:
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Fire Protection:
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Randomly selected fire extinguishers were accessible and l
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inspected on schedule.
Fire doors were unobstructed and in their proper position.
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Ignition sources and combustible materials were controlled in
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accordance with the licensee's approved procedures.
Appropriate fire watches or fire patrols were stationed when
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fire protection / detection equipment was out of service.
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Vital Instrumentation:
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Selected instruments appeared functional and demonstrated l
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parameters within Technical Specification Limiting Conditions
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Housekeeping:
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Plant housekeeping and cleanliness were in accordance with j
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licensee programs.
Minor house heping deficiencies which were identified were promptly j
corrected by the licensee.
No significant conditions were identified.
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2.0 ' Radiological Contro s i
2.1'.Unmonitored Release paths j
On August 22, 1990, a group operating supervisor (GOS) during a routine tour.of the plant identified a potential unmonitored release path at the turbine building northwest roof. The GOS notified Radiological Controls,.
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i material directly to the environment, The licensee sampled-the effluent to quantify and characterize the radioactive-material being released into the environment. Also, the-l velocity of the effluent stream was measured.
Then, the licensee blocked i
._the path'by inserting a plug.in the plastic piping at the turbine building i
roof. This. secured the release.
Inspection report 50-219/90-13 evaluated
the offsite radiological consequences of this release and concluded no
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regulatory limits were exceeded and the consequences of the release were small.
This release path was established when main steam leaking through reheater protection system isolation valves entered the turbine building floor drain system through an open drain valve.
In close proximity to this hub drain is a floor drain where temporary plastic pipe had been installed routed to the turbine building roof.
This plastic piping was sealed to the floor drain by a plastic contamination control device.
Because this area of the turbine building has been operating at a pressure positive to atmospheric and with the completion of the flow path from the floor drain system from the turbine building roof, radioactive steam was forced through out of the turbine building and into the atmosphere.
Radiological controls technicians measured the velocity at the release point to be four ft per second. The temporary plastic piping was approximately two inches in diameter.
The temporary plastic piping which was routed from the turbine building mezzanine floor drain to the turbine building northwest roof was not documented on any plant orawing nor was a mechanical variation in place to review ano control the modification. As a result, no safety evaluation existed for the temporary modification. The licensee was unable to identify the purpose for the temporary modification. Along with operating conditions inside the turbine building, this unauthorized modification allowed an unmonitored release of radioactive material for approximately two years.
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The. unauthorized temporary piping was a deviation-from plant drawings.
NRC. inspectors toured the reactor building to identify additional plant configurations which may be unauthorized.
The following configurations were questioned:
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Isolation condenser valve packing gland leak-off lines contained threaded connections, teflon tape, and appeared to be a temporary
. configuration. Although P & 10 drawing GE148F262, Revision 25, shows
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this piping, it may have been added to the drawing as a result of field walkdowns to identify actual plant as-built conditions.
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Standby. liquid control pump leak-off drains consisted of threaded'
connections and were directed to the floor drain system without any pipe supports. 'Although this configuration is shown on P & 10
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14SF723, this too may have been added to the drawings as a result of field-walkdowns.
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In the reactor building, on the 23 ft elevation, temporary fan SF-12
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drain line is clamped to a torus pressure sensing lin.--
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In the reactor building, on 23 ft elevation, in the northwest corner north wall by core spray system I, exists a pipe penetrating the reactor building wall with a valve, no valve number, and the end of the pipe is capped with a threaded connection.
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Inside the reactor building 23 ft elevation by the south wall a pipe penetrating the floor from the torus room with a valve and and a nipple. The valve has no valve number and the configuration appears tempora ry. Also in close proximity there was an unconnected pipe on the wall with an unidentified valve.
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In the reactor building 23 ft elevation by the south wall is 1 in.
copper tubing with threaded connections and teflon tape with valves that appear to be temporary (valves are tagged with the following designation, SA-HV-342 and 343).
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A 2 in, metallic drain pipe was located north of containment spray heat exchanger 1-3 running along the floor, along the wall and then up the wall.
This installation appeared temporary in that it was resting on a wooden block and had marginal support.
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A temporary line had been connected to the demineralizer water system, consisting of tubing and a valve. The apparent function of this line was to provide a source of water for instrument and controls techni-cians'in performing scram discharge volume level surveillances.
This configuration was not tagged and not controlled as a mechanical variation.
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In the reactor building 51 ft elevation, by demineralizer valve
.V-12-133, was a. temporary valve which was installed and was not controlled as a mechanical variation.
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Inside.the reactor building at the 23 ft elevation, in the east wall, through a penetration was a rubber hose with temporary valves inside and outside the secondary containment. This configuration appeared temporary and was not controlled as a mechanical variation.
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Inside the reactor building at the 23 ft elevation by the. north wall and outside the. north wall was a temporary air supply from the joy-air compressors.
Inside the reactor building is a manifold with many-temporary valves. These are not controlled as mechanical variations.
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From the-temporary air supply inside the reactor building is a 2 in.
.line which extends.all the way to the refueling floor 119 ft elevation. -This temporary configuration is not controlled as a mechanical variation.
Inspectors walked down these configurations with the licensee. At the end
.of.the inspection period the licensee was still evaluating and researching
.the acceptability of these configurations.
The license did not identify any safety related equipment that was inoperable due to the above conditions.
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Previous NRC inspections have identified questions regarding how config-uration control is maintained in the Oyster Creek work management system.
This was initially documented in inspection report 50-219/88-16 and then in inspection report 50-219/89-04.
The latter documented a violation where a modification to the intermediate range monitor switch was performed under the work management system without proper documentation.
The cover letter to this report requested that GpVN identify in their response to the violation what feature of the Oyster Creek work management system identified proposed work as impacting plant configuration control.
The above listed items indicate there is a present concern regarding imple-
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mentation of work at Oyster Creek and proper configuration control. This
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item will be unresolved pending licensee evaluation of the above plant
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configurations and the licensee evaluation and implementation of corrective
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action to provide controls in the work management system to maintain plant configuration.
(Unresolved item 50-219/90-16-02)
3.0 Maintenance and surveillance 3.1 Installation of Temporary Shielding On September 1, 1990, inspectors observed the radiological surveys and installation of temporary shielding in preparation for cleaning contain-ment spray. system No. II heat exchangers. The surveys identified hot spots from a reactor water cleanup' drain line located above the heat exchangers about 20 feet above the reactor building floor. After install-ing six lead blankets, radiological surveys identified the need to install two additional blankets. One small area of this piping read 12 rem per hour on contact and one tem per hour at 12 inches.
The inspector reviewed radiological work permit 90-833 and rattiological survey No. RCS 90-9782._ Inspectors observed the radiological controls technician survey of the piping, the maintenance mechanic's installation of two lead blankets, and the radiological post-installation survey. The inspector verified that worker dosimetry placement was in accordance with the radiological work permit. As a result of this work the radiation
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levels were reduced from one rem per hour at 12 inches-to 280 mrem per hour at 12 inches. Continuous radiological controls technician coverage was provided. The job supervisor was present during the shielding
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installation. This work was well planned and executed.
3.2 Monthly Surveillance Observation The inspector observed performance of the following surveillance, from the
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-control room.and from the reactor building.
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Procedure 609.3.002, Rev. 26. " Isolation Condenser Isolation Test Calibration"
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This procedure verifies the setpoints of the differential pressure gauges in the isolation condenser steam condensate return lines which monitor line breaks.
Performance of this surveillance requires team work between a designated control room operator to position control switches, an I & C technician stationed at the control room to check for relay positioning, and two I & C technicians at the instrument rack to insert the test signal.
The control room operator performing the surveillance was methodical and appropriately followed the procedure.
The operator was alert and respon-sive when the system was disabled during the surveillance as required by the procedure.
Appropriate approval and authorization to perform the surveillance was obtained, prerequisites were verified, and the test equipment was within its calibration period. A deviation report was prepared when one of the instruments did not meet the as-left' acceptance criteria.
The trip points were found to be acceptable for technical specification requirements.
These' instrumentations are scheduled to be replaced during the upcoming 13R outage.
4.0 Engineering and Technical Support 4.1 Core Spray Relief Valves On August 29,- the licensee identified premature lif ting of Core Spray relief valve V-20-42..The valve nominal lift setpoint was 350 psig and water was observed with pressure at about 320 psi (system pressure at the booster pump. discharge during testing). The valve was manufactured by Lonegran (model R-30H). The~ replacement valve was also manufactured by Lonegran (model.W-303) and-had recently been received from Wylie-Laboratories after readjustment and testing, This valve did not lift during subsequent surveillance testing.
Both valves ~ have previously exhibited some drif t in setpoints (Inspection
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Reports 50-219/89-07 and 90-09). As a result, the licensee formulated an
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g action plan to more accurately characterize the'setpoint behavior of these valves. The safety. significance of these events is minimized by the ability to detect leakage during routine surveillance tests _and thus identify the conditions. At the end of the inspection period, the li:ensee was in the process of implementing corrective actions identified it their review.
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- 5.0 Observation of Physical Security During daily tours, the inspectors verified that access controls were in accordance with the Security plan, security posts were properly manned, i
protected area gates were locked or guarded and that isolation zones were free of obstructions.
The inspectors examined vital area access points to
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verify that they were properly locked or guarded and that access control was in accordance with the security plan.
No significant observations were made.
6.0 Safety Assessment / Quality Verification 6.1 Core Spray System II Seismic Restraint Damage On September 6,1990, the licensee identified a damaged snubber (NZ-2-S15)
on core. spray system 11 main piping at the 51 f t elevation in the reactor building.
This deficiency was documented in material nonconformance report (MNCR)90-120, Later the same day the licensee identified that core spray strut NZ-2-H44 was damaged. The strut had pulled away from the muunting surface. This deficiency was documented as MNCR 90-121. The damaged strut was in close proximity to the damaged snubber.
The strut damage was discovered by Manager of Radwaste Operations while performing a backshift tour. The location of the strut was in an area that used to be a locked high radiation and contaminated area.
Recent licensee decon-I tamination efforts have restored normal access to this area.
i The damaged snubber was replaced on September 7, 1990.
Technical Specification 3.5.A.8.a. requires with one or more snubbers inoperable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> replace or restore the inoperable snubber to an operable status. Technical Specification '3.5.A.8.c. requires if the snubber cannot be replaced within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> declare the protected system inoperable and follow the appropriate action statement for that system.
Licensee corrective action satisfied Technical Specification requirements without the need'to. consider Core Spray inoperable because of the damaged snubber.
The licensee performed an analysis of the effects of the inoperable strut on the operability of Core Spray system II. The seismic model was modified to delete the strut. The results showed that pipe stresses were
within the code limits. All seismic supports within'50 ft.in either direction from the strut were operable; however, the factor of safety for one snubber dropped from 27 to 13.
Licensee evaluation concluded this factor of safety was sufficient to justify system operability.
Based on the results of this' analysis the licensee concluded that core spray i
system II was operable. The strut was repaired on September 11.
The licensee performed a walkdown of the core spray piping in proximity to the damaged snubber and strut and identified no other deficiencies affecting the core spray system.
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Because a similar def tciency had been identified on the snubber in February 1990, the licensee formulated an action plan to identify the root cause of the damage to the seismic supports on core spray system II. This plan consisted of reviewing testing configurations, observing tests, i
reviewing system history, evaluating the differences between system I and II, investigating operation of system check valves, verifying the system is being maintained full of water, and developing a thermal-hydraulic model of the Core Spray system. At the end of the inspection period, the licensee was in the process of implementing this action plan.
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The inspectnrs reviewed the licensee actions regarding the replacement of the snubber, the results of the evaluation of system operability with the
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damaged strut, and the action plan. The inspectors found that adequate j
evaluation of system operability was performed.
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Licensee identification of the damaged strut was noteworthy in that this
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area of the plant only recently has been available for routine management c
tours Without-this access, this deficiency may not have been identified.
j 6.2 Condensate Pump Impeller Degradation j
During refueling outage 12R, the licensee replaced the "A" condensate pump rotating assembly. The old assembly was sent to the manufacturer for s
inspection and evaluation.
Some pitting was observed on the pump impeller.
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The inspectors questioned the licensee's evaluation of the cause of this-degradation.
Licensee evaluation concluded the wear associated with the impeller was due to normal' wear in a limited suction head application. The vendor's manual for this pump indicates it is designed for pumping fluids at or near.the boiling _ point and thus net positive suction head is necessarily q
limited.. The licensee concluded this was normal wear. The wear was
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identified by monitoring pump performance. - The licensee plans to replace I
the?"C" pump rotating assembly during refueling outage 13R. There is i
currently no plan to replace the "B" pump. The inspectors had no other i
questions.
7.0 Review of Previously Opened Inspection Findings (Closed) Unresolved Item 86-30-01.
Inspection Report 50-219/89-16 reviewed this item and left it open pending implementation of a formalized i
inspection monitoring program by the licensee. The licensee has imple-mented an inspection specification (ST-1302-53-051, Rev. 0) to identify the reactor building concrete cracks to be inspected, the inspection
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interval, and the acceptance criteria. The inspector also reviewed work request #751155 which erects scaffolding for implementation of this speci-
.fication for work to be' conducted during the the upcoming refueling outage.
The licensee has formalized the inspection requirements and acceptance criteria and has made preparations for conducting inspections during the upcoming refueling outage. This unresolved item is clo:ed.
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(Closed) Unresolved Item 86-33-01.
Ins,ection report 50-219/86-33 reviewed a plant structural deficiency where 80 af 137 hydraulic control units (HCU) were not properly installer'.. After the licensee concluded the HCOs could not be consiJered oparable, repairs were made and a Licensee Event Report 86-22 was sutmitted. Unresolved item 86-33-01 was opened to track generic concerns of inoperability of safety related equipment due to inadequate construction and the failure of the licensee to identify and resolve these deficiencies.
Recent NRC inspection resulted in enforcement actions in this area.
Inspection reports 50-219/89-14, 89-16, and 89-23 cited the licensee for failure to identify and correct deficient conditions. The most recent report resulted in an enforcement conference on December 5, 1989.
In this meeting the licensee presented their overall plans and corrective actions to improve their ability to identify and resolve deficient conditions.
Based on these recent inspection findings, enforcement actions, and licensee corrective actions, this item is closed.
(Closed) Unresolved Item 86-38-03. Control Room Habitability.
This unresolved item questioned the adequacy of the licensee's control of the control room kitchen / bathroom exhaust fan EF1-24. An update of this issue was provided in inspection report 50-219/89-21. This update indicated this item would be reviewed after the needed technical specification amendment for the control room HVAC system is finalized.
The-licensee's chlorine release analysis for the 150 lb. onsite st-age indicated that with an-infiltration rate less than 1750 cfm, the chlorine concentration would be maintained below the toxicity limit inside the control room..The licensee also indicated that the 1750 cfm infiltration rate is met with the subject exhaust fan EF-1-24 not running.
The licensee's submittal also indicated the fan is run only when the kitchen / bathroom is in use. Administrative control of fan operation, in addition to a-five-minute timer added to the fan controls, ensures
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adequate control of the fan.
To verify adequate control of fan operation, the inspector reviewed the
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following procedures:
331.1, Rev. 1, " Control Room and Old Cable Spreading Room Heating.
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. Ventilation and Air Conditioning System,"
2000 RAP.3024.03. Rev. 28. BOP Annunciator Response, Procedure,
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Window K-4-e, "NRW Chlorine Leak," and; 2000 ABN-3200.33, Rev b., " Toxic material Release - No Radiation
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involved."
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The inspector walked down the annunciator response procedure (ARP) for window K-4-e with a control room operator. The ARP directs the operator to place the control room HVAC system in the " full recirculation" mode in accordance with Procedure 331.1 and refers to procedure 1000 ABN-3200.33 in addition to Procedure 326.1, "NRW Service Water Chlorination System,"
for corrective actions.
Procedure 331.1 does not contain instructions on how to place HVAC system in full recirculation mode; however, it refers to procedure 2000-ABN-3200.33 for emergency operation during a chlorine release. The ABN procedure references the panel, mode switch and indicating lights for the HVAC system components. The inspector observed a posting en the bathroom wall that directs the user to close the damper and stop the fan after each use.
The licensee's procedure for maintaining control room habitability in case of a chlorine release is weak in that no specific instruction is provided on how to place the control room HVAC system in the full recirculation
mode. Also, the procedure step for verifying the kitchen / bathroom fan is off is easily missed by the operator. The inspectors discussed these ebservations with operations management. At the end of the inspection period the licensee had initiated procedure changes to address these observations.
The safety significance of these procedure weaknesses is low because the step is simple and the operator executes the step by turning the mode switch and verifying proper indication.
This unresolved item also questioned the adequacy of the licensee's plant configuration control since the timer on exhaust fan EF 1-24 was installed without documentation. This issue is similar to configuration control violation 50-219/89-04-01. This issue will be reviewed with licensee's corrective action for violation 89-04-01 and the unresolved item of
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Section 2.1.
Unresolved item 86-38-03 is closed.
(Closed) Unresolved item 50-219/87-04-01.
This unresolved item questioned the need for the offgas sample pump when-in startup or run mode. During January 1987 the sample pump stopped working while the reactor temperature was above 212 degrees F and the plant wi.s in the shutdown mode.
The licensee was reviewing the need for the sample pump under these conditions.
The air extraction offgas-(AEOG) system removes noncondensible gases from the condensers and the turbine gland seal exhaust and exhausts them through the plant stack after allowing for monitoring and decay in a 48 inch offgas-A header. This flow path is automatically isolated upon high radiation in the offgas or the main steam lines. During startup, before the air ejectors are placed into service, the mechanical vacuum pump maintains condenser vacuum. The exhaust from the mechanical vacuum pump is directed
~through a 30 inch header into the plant stack. Upon high radiation in the main steam line, this flow path is isolated, s
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The offgas line is continuously sampled using vacuum in the "B" condenser as the driving force for sample flow. During startup and shutdown when condenser vacuum is not established, a sample pump provides the driving force for sample flow.
Technical Specification, Table 3.1.1, paragraph I, requires the high radiation isolation function of the offgas system to be operable in the run and startup modes, and also in the shutdown and refueling modes unless the reactor temperature is below 212 degrees F and the vessel head is removed or vented. A note to this technical specification indicates high radiation instruments for the offgas line shall be operable during the main condenser air ejector operation.
The inspector reviewed the flow diagram for the AEOG system and portions of the plant operating procedures, including 203.2, Rev. 37, " Plant Cooldown from Hot Standby to Cold Shutdown," 201.2, Rev. 39, " Plant Heatup to Hot Standby," and 325, Rev. 23, " Air extraction and Offgas System."
Also reviewed were the alarm response Procedure 2000-RAP-3024.1, Rev. 42,
'!NS$$ Annunciator Response Procedures for Windows 10F-1-c, Offgas Hi-Hi,
-10F-1-d, Stack Effluent Hi-Hi," and Procedure 2000-ABN-3200.26 Rev. 3
" Increase in Offgas Activity."
The mechanical vacuum pump exhaust flow is not served by the offgas radiation monitors, thus, there is no automatic isolation of the offgas line (30 inch header) upon high radiation level in the offgas line (48 inch header). Upon high radiation in the main steam line this exhaust is isolated.
Since the mechanical vacuum pump is only operated at a power
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level below 5%, this provides adequate protection in case of an accident.
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The sample pump is required to draw a sample for the offgas radiation monitors only when a vacuum is not available in the "B" condenser. During
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normal startup and shutdown the air ejectors are not in operation when-l condenser vacuum is not present. Hence high radiation isolation of the
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offgas line is not needed.
If vacuum in the "B" condenser is lost during a transient, the reactor will be shut down.
The. inspector concluded that the offgas sample pump is only required to be running when the offgas air ejectors are operating but unable to maintain
a vacuum in-the "B" condenser. The technical specification is conservative.
The licensee is currently preparing an amendment request to clarify this i-technical specification. This item is closed.
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(Closed) Unresolved Item 87-04-02. Deficiencies in containment spray logic.
l The NRC requested in a letter to GPUN dated April 8, 1990, an evaluation of the
ability of Oyster Creek to meet the acceptance criteria for emergency
core cooling as.specified in 10 CFR 50.46 with a containment spray logic i
deficiency (Inspection Report 50-219/89-06&O9). GPUN responded in a letter dated August 24, 1990.
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GPUN concluded the only 10 CFR 50.46 acceptance criteria affected by this logic deficiency was the ability to establish long term cooling. GPUN
indicated that independent of the logic deficiency, operator action is i
required to establish torus pool cooling. GPUN further concluded that a
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time frame of over two hours was available for the operator to establish torus pool cooling.
Based on engineering judgment GPUN concluded this time was adequate for operators and technical support staff to take action to ensure that long term core cooling was maintained.
Overall, GPUN concluded that Oyster Creek meets the acceptance criteria contained in 10 CFR 50.46 with the valve logic design deficiency. Manual r
action is required to satisfy the long term cooling criteria and sufficient time is available for the operator to take manual action.
Currently operators are aware of the design deficiency and are trained in the method to override this deficiency and are provided instructions and procedures to override the valve logic, should it be required.
NRC
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inspection report 50-219/89-09 reviewed these actions, j
Based on GPUN review of the ability of the plant to have met acceptance criteria for emergency core cooling system with this valve logic deficiency, this item is closed.
8.0 Verification of Safety Issue Management System (SIMS) Items Item I.C.I.2.a and I.C.1.3.a. "Short Term Accident and Procedures Reviews" TMI Action Plan Item I.C.1.2.a required reanalyzing and proposing
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procedure guidelines for inadequate core cooling.
Item I.C.1.3.a.
required reanalyzing and proposing procedure guidelines for other transients and accidents. Action plan items I.C.I.2.b. and I.C.1.3.b.
required the licensee to review and revise transient and accident procedures. Oyster Creek inspet. tion report 50-219/87-13 verified the
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revision of procedures. Th 4 implementation or procedure revision
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completes the action to perform the analysis.
Items I.C.I.2.a. and I.C.I.3.a. do not reqsire verification by inspection.
This item is closed.
Item 1.D 2.2 and Item I.D.2.3. " Installation and implementation of Safety Parameter Display System
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On January 17 and January 18, 1990, the NRC staff conducted an onsite
audit of GPUN safety parameter display system (SPDS). Oyster Creek's SPDS
was reviewed against the requirements of Supplement I to NUREG-0737 which
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outlines eight requirements.
NRC letter dated January 30, 1990 documented
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the results of the audit.
Oyster Creek SPDS satisfied the following criteria:
The SPDS should rapidly and reliably aide the control room operators
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in determining the safety status of the plant;
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The SPDS shall be located convenient to control room operators;
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Procedures should be developed and operators trained with and without
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the SPDS available; The SPDS shall be designed to incorporate accepted human factors
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principles; and, 1.
The SPDS shall be suitably isolated from electrical and electronic
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interference with equipment and sensors that are used for safety systems.
The NRC staff audit found the Oyster Creek SPDS deficient in not supplying the minimum information to plant operators about the five critical safety functions (reactivity control, reactor core cooling, heat removal from the primary system, reactor coolant system integrity, and containment conditions). The Oyster Creek SPDS only provided containment isolation demand signal indication, rather than containment isolation valve position indication. Also, panel 11-F in the control room does not provide control room personnel with indication for all containment isolation. valves.
In a previous safety evaluation dated March 5, 1986, the NRC staff determined that a containment isolation demand signal indication in the SPDS is an acceptable input to the containment conditions critical safety function. NRC safety evaluation dated June 28, 1990, reflects that Dyster Creek's SPDS satisfies this NUREG-0737, Supplement I, requirement.
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The licensee responded to the above deficiency-(letter dated May 17,1990)
indicating that a control room operator would be directed to confirm the containment isolation demand signal and verify satisfactory completion of containment isolation. This is controlled by plant procedure 312,
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" Reactor Containment Integrity Atmospheric Control." The licensee concluded the display of the containment isolation demand signal along with operator verifications of valve position indications satisfies the need-to verify containment isolation.
NRC inspectors verified Procedure 312, Rev. 52 Section 11.3, contained the necessary steps to verify the position of containment isolation valves.
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The NRC audit team also determined that Dyster Creek SPDS did not fully meet the following requirements:
SPDS should provide a concise display of critical plant variables to
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control room operators; and, SPDS will continuously display safety status information.
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.The following specific concerns were identified:
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A separate alarm status monitor is located 90 degrees away from and
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to the right of the SPDS monitor; The SPDS monitor and the separate alarm status monitor are not
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totally dedicated because non-SPDS displays can be displayed on the monitors; and, On displays below the main menu the SPDS monitor does not indicate a
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change in status for the five plant specific safety functions.
Licensee response and corrective action to address these concerns was indicated in their letter dated May 17, 1990. The licensee committed to modifying the SPDS display so that critical safety function status boxes will appear on the message line of all displays on every monitor of the plant computer system.
This arrangement will provide a continuous display of critical safety function status except for a brief period when error messages may interrupt.
Five boxes will be displayed on the bottom line of each monitor, one for each critical safety function.
The licensee addressed the concern that monitors are not totally dedicated by dedicating a monitor to displaying plant computer system alarms.
including SPDS alarms.
An NRC safety evaluation dated Junr. 28, 1990, reviewed the corrective.
action and responses of the GPUN letter (May 17,1990), and concluded that upon satisfactory implementation of these actions, the Oyster Creek SPDS system will meet all criteria of Supplement I to NUREG-0737.
Inspectors reviewed the present configuration of Oyster Creek SPDS system and verified that alarm boxes are continueusly displayed (except for.the-short period of time where error messages are displayed) on the message line of control room and technical support center plant computer monitors.
These boxes continuously indicate the status of the critical safety functions and display a change in the alarm status. These features are independent of the screen which is displayed.
Inspectors also verified
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that a monitor in the control room has been dedicated to continuously
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. displaying alarms.
L Based on the results of NRC staff audit of January 17.and 18, 1990,
licensee corrective actions to address-the deficiencies of.the audit. NRC-
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corrective actions of GPUN letter dated May 17, 1990, TMI items I.D.2.2.
and I.D.2.3 for the installation and implementation of SPDS systems are-closed.
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i Item II.E.4.1.2 and Item II.E.4.1.3 Associated with Dedicated Hydrogen
On January 10, 1983, the NRC issued Generic Letter 83-02 NUREG-0737, Technical Specifications. On May 30, 1985, the NRC issued a letter to GPUN containing the safety evaluation of the licensee response to Generic
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letter 83-02. This NRC letter closed out Generic Letter 83-02.
Contained within the NRC staff safety evaluation is TMI Item II.E.4.1 for dedicated hydrogen penetrations.
Item II.E.4.1 required that plants using purge /repressurization systems for post accident combustible gas control of the containment atmosphere, have containment penetrations dedicated to that service. The acceptable i
alternative was a combined design for use by purge /repressurization
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systems and other systems which met the requirement of Section 50.44 of 10 CFR 50.
By letter dated August 2, 1982, the licensee requested exemptions to 10 CFR 50.44. The staff, by letter dated May 21, 1984, responded that i
Generic Letter 84-09, "Recombiner Capability Requirements of 10 CFR 50.44
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(c) (3) (ii)," dated May 8, 1984, provided guidance for obtaining the
relief the licensee requested. The implementation of Item II.E.4.1 will be completed as part of the staff's review of licensee's responses to
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Generic letter 84-09.
NRC safety evaluation dated May 30, 1985, closed
Item II.E.4.1 for purposes of _ tracking in the TMI items system. Any
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modifications that may be required as a result of 10 CFR 50.44 are currently being tracked-under licensing TAC No. 62980.
TMI items
II.E.4.1.2 and II.E.4.1.3 do not require inspection verification.
This
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Item II.K.3.28, " Qualification of Automatic Depressurization Systein ( ADS)
[CCumulators'I i
The automatic depressurization system at Oyster Creek consists of five electromatic (EMRV) re' lief _ valves. These valves are solenoid / pilot valve operated and do not use a pneumatic supply to open.
This item is not
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applicable to Oyster Creek.
No inspection verification is required for this TMI item.
This item'is closed.
Item II.K.3.13.b., "High Pressure Cooling Injection and Reactor Core holationCoolingSystemInitiationLevelsModificatioTih
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Oyster Creek does not have high pressure coolant injection or reactor core
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isolation enoling systems.
Thus, the requirement to separate the i
initiation level _ signals for these systems is not applicable to Oyster Creek. No inspection verification is required for this item. This item is closed.
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Item II.K.3.14 " Isolation of Isolation Condensers on High__ Radiation" This item provided for the movement of the isolation condenser high radiation isolation signal from the steam supply line to the condenser vent. The intent of this change was to improve the reliability and availability of isolation condensers by preventing unnecessary isolations.
Oyster Creek does not have an isolation signal on high radiation in the steam supply line.
Neither does Oyster Creek have an isolation signal on high radiation in the condenser vents. NRC staff reviewed the Oyster Creek configuration which requires manual isolation on high radiation in the condenser vent and concluded it is sufficient to provide the amount of flexibility and system availability intended by this item.
NRC staff review of this item is documented in a safety evaluation dated December 18, 1981. The modification of TMI item II.K.3.14 is not applicable to Oyster Creek. No inspection verification for this item is required.
This item is closed.
Item III.D.3.4.3, " Control Room Habitability" Licensee commitments for upgrade of the Oyster Creek control room were indicated in GPUN letter dated June 4,1985.
This letter outlined the design objectives for control room modifications. During the last refaeling outage, 12R, the licensee completed implementation and upgrade of the control room Heating, Ventilation and Air Condition (HVAC) system.
T!as modification included installation of a second train (B train) to satisfy single failure criteria.
During the outage a Safety System Outage Modification Inspection (550MI)
reviewed the design for the proposed modification (Inspection Report 50-219/88-202). This report questioned licensee assumptions regarding heat loads and control room occupancy used in the calculation for control
room heatup, the impact of existing low flow in the "A" HVAC system, and procedural guidance to operators to open doors to assist in control room cooling in that it did not consider radiological effects. Also, questions were raised regarding-the lack of procedural guidance specifying the outside ambient air temperature for which the fan only mode should be used and the correctness of a caution statement in Station Procedure 331 stating that controi.0om instruments are affected at 90 degrees F.
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The licensee responded to these concerns (GPUN letter dated December 12, 1988).
The licensee re performed the calculation for control room heatup after the loss of offsite power.
Included in this analysis was the i
existirig flow in the "A'
HVAC system (about 10 percent below design). The licensee concluded in its reanalysis that control room temperature would not heat up to 104 degrees F (design limit) for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after a loss of offsite power.
The other items were addressed by implementing procedure changes to:
Indicate the outdoor temperature for which the fan only mode should
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Remove the caution in Procedure 301 indicating control room
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instrumentation is affected at 90 degrees, Revise the procedure indicating that operators are not to open the
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doors in the event of radiological releases, and Provide cautions indicating that 104 degrees F is the temperature at
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which instrument reliability may degrade.
Station Procedure 331.1, " Control Room and Old Cable Spreading Room Heat, Ventilation and Air Conditioning System," was generated to provide operat-ing instructions for the new and the old trains of the control room HVAC system. The inspectors reviewed revision 1 of this procedure and verified the following:
Step 5.1.2.3 specifies limits on outside air temperature for using I
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the fan only mode (89 degree upper limit).
Old Procedure 331, " Office Building Heating, Ventilation and Air
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Conditioning System," Rev. 19, did not provide any caution in regard to room instrumentation degradation at 90 degrees, Steps 5.1.1.2 and 5.1.2.4 specify during a radiological release to
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minimize traffic through the control room doors (i.e. keep doors L
closed as much as possible), and Pages 11 and 15 of the procedure contain a cautinn indicating that
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instrument reliability may degrade if the control room temperature reaches 104 degrees F.
This may occur as early as two hours after a loss of control room HVAC.
During the onsite portion of the SSOMI inspection (report 50-219/88-203),
NRC. inspectors questioned the "A" control room HVAC system flows and bypass leakage. The. licensee addressed this concern in a letter dated January 12, 1989.
The response was accepted as indicated in the cover letter to SSOMI report 88-203 dated March 16, 1989.
The onsite team also performed walkdown and visual verifications of the
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installation of "B" control room HVAC system.
Inspection report
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50-219/88-203 indicated no deficiencies'were identified as a result of documentation or walk through of the installation. The team also reviewed F
the startup and test-procedure, TP-254/11, and identified the following
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Insufficient acceptance criteria was provided for heating and cooling, 2.
No. temperature measurement was taken in the lower cable spreading
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Test methodology would not permit the control room "B" HVAC system to be declared operable until a test verifying heat removal capability
could be run with the outside air temperature at 89 degrees.
The licensee committed to revising startup and test procedure Tp-254/11 to correct these deficiencies.
NRC inspectors verified the configuration for the "B" control room HVAC system has been incorporated into controlled site drawings (3E-826-21-2000, Rev. 1), and that approved procedures are in existence, (i.e. Station Pro-cedure 331.1), to provide instructions to control room operators in the operation of the system.
Inspectors also walked down the system, spot checked instrumentation and calibration, and spot checked current component status.
No deficiencies
were identified.
On January 17 and 18, 1990, the NRC staff conducted an audit of GPUN's detailed control room design review in support of NUREG-0737, Supplement I, requirements.
In a letter dated January 30, 1990, the audit team documented its conclusion that the licensee has satisfied the nine requirements for NUREG-0737, " Detailed Control Room Design Review."
Amendment #139 to the Provisional Operating License #DPR-16 for Oyster Creek was issued on May 29, 1990. This amendment revised technical specifications, sections 3.17 and 4.17.
Specifically, the changes are as follows:
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Two control room HVAC systems shall be operable during all modes of operation, p.
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Addition of new limiting conditions for operation for the cont.rol room, and i
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Delete surveillance to determine the makeup air plus infiltration air less than or cqual to 2,000 cfm to the control room envelope for each r
control room HVAC system.
Since the NRC staff is currently reviewing the iodine source term for the
design basis loss of coolant accident, thyroid exposure limits are being addressed in a an action separate from NUREG-0737 requirements.
Inspectors reviewed the test results from surveillance test 654.4.003,
. Revision 2, " Control Room HVAC System Operability Test," which was performed on July 24, 1990. The test was completed satisfactorily.
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Based on_ licensee modifications to Oyster Creek control room, NRC inspection of the design and implementation of the modification, NRC audit of detailed control room design review requirements, and implementation of technical specification changes and NRC safety evaluation dated May 29, 1990, TMI item III.D 3.4 is closed. Thyroid exposure limits are being addressed as a separate action from NUREG-0737.
9.0 Inspection Hours Summary Inspection consisted of 175 direct inspection hours; 30 of these direct inspection hours were performed during backshift periods, and 11 of these hours were deep backshift hours.
10.0 Exit Meetina and Unresolved Items 10.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to senior licensee management at the conclusion of this inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was
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provided to the licensee during the inspection.
No proprietary
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information is included in this report, 10.2 Attendance at Management Meetinos Conducted by Region Based
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Inspectors During this _ inspection period the resident inspectors attended exit l-meetings for inspections 50-219/90-13, 14, 15, and 17. At each of these
meetings the lead inspector discussed inspection activities and findings
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with senior licensee management.
L 10.3 Unresolved Items Unresolved items are matters for which more'information is required in
order to ascertain whether they are acceptable, violations or deviations.
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- An unresolved item is' discussed in section 2.1 of this. report.
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