IR 05000298/1987003
| ML20211E524 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 02/11/1987 |
| From: | Dubois D, Jaudon J, Plettner E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20211E490 | List: |
| References | |
| 50-298-87-03, 50-298-87-3, IEB-85-001, IEB-85-002, IEB-85-1, IEB-85-2, NUDOCS 8702240331 | |
| Download: ML20211E524 (18) | |
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APPENDIX B U. S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-298/87-03 License: DPR-46 Docket: 50-298 Licensee: Nebraska Public Power District (NPPD)
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P. O. Box 499 Columbus, NE 68601
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Facility Name: Cooper Nuclear Station (CNS)
Inspection At: Cooper Nuclear Station, Nemaha County, Nebraska Inspection Conducted:
January 1-31, 1987
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Inspectors: [. 4. Nh E/2!F *1 E. A. Plettner, Resident Inspector, (RI)
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D. L. DuBois, Senior Resident Inspector, (SRI)
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Approved:
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l J P./Jaud/n, Chief, Project Section A, Date
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Reabtor(Project Branch l
l 8702240331 870213 PDR ADOCK 05000298 G
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Inspection Summary Inspection Conducted January 1-31,1987(Report 50-298/87-03)
Areas Inspected:
Routine, unannounced inspection of IE Bulletins, reactor coolant system hydrostatic test, plant startup from refueling and startup testing, shutdown margin, core thermal power evaluation, core power distribution, nuclear instrumentation calibration, plant trips-safety system challenges, operational safety verification, post modification testing, and monthly. surveillance and maintenance observations.
Results: Within the areas inspected, two violations were identified (failure to provide adequate procedures and failure to follow procedures, paragraph 5).
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DETAILS 1.
Persons Contacted Principal Licensee Employees
- G. R. Horn, Division Manager of Nuclear Operations
- J. M. Meacham, Senior Manager, Technical Support
- C. R.. Goings, Regulatory Compliance Specialist
- D. R. Robinson, Supervisor, Operations Quality Assurance
- R.. D. Black, Supervisor, Operations
- H. A. Jantzen, Supervisor, Instrument and Control
- M. D. Hamm, Supervisor, Security
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The NRC inspectors also interviewed other licensee employees during the course of the inspection.
- Denotes those present during exit interview January 30, 1987.
2.
IE Bulletins The following IE Bulletins were reviewed by the RI for applicability to Cooper Nuclear Station and to determine if the licensee had performed required actions:
(Closed) IE Bulletin No. 85-01, " Steam Binding of Auxiliary Feedwater Pumps."
The bulletin describes the circumstances which caused auxiliary feedwater pumps to become inoperable at specified operating pressurized water reactor facilities as a result of steam binding. Attachment 1 of the bulletin identified all Pressured Water Reactor (PWR) licensee's required-to respond. CNS is a Boiling Water Reactor facility and was not identified as one of the respondents listed in Attachment 1 of the bulletin.
This item is closed.
(Closed) IE Bulletin No. 85-02, "Undervoltage Trip Attachments of Westinghouse DB-50 Type Reactor Trip Breakers."
The bulletin addresses reliability problems of Westinghouse DB-50 type breakers used for reactor trip breakers at operating Westinghouse (PWR)
facilities. CNS doesn't use Westinghouse DB-50 type reactor trip breakers in its reactor protection system.
This item is close m
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3.
Reactor Coolant System Hydrostatic Test The RI reviewed the licensee's procedures for a reactor coolant system hydrostatic test and witnessed the performance of that test on January 1, 1987. The performance observations included:
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Verification that the pressure boundary isolation valves were
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maintained in the correct position during the test.
The reactor coolant system was protected from overpressure by code
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safety valves set in the range of 1240-1250 psig.
Water quality met chemistry requirements.
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The reactor coolant system was vented during filling operations.
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Pressurization temperature was kept above the nil ductility
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transition temperature.
Test instrumentation response and data measurements were recorded.
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Verification of proper safety-related systems pressure switch
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actuations and resets for those switches that sense reactor coolant system pressure in order to perform their safety functions.
Verification that maintenance performed to reduce leakage did not
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negate the performance of.the test or test results.
On-the-spot procedure changes were approved and implemented as
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permitted by administrative procedures.
Drywell inspections were conducted prior to and following the test.
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Availability of safety systems and adherence to limiting conditions
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for operations required by the Technical Specification were
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maintained.
The hydrostatic test was performed in accordance with Section XI of
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j the ASME Boiler and Pressure Vessel Code, 1974 Edition. Test
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pressure was 1.10 times the CNS nominal operating pressure of
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1005 psig.
This inspection was conducted to ensure that the primary system hydrostatic test was performed in accordance with licensee commitments,
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industry standards and codes, CNS Operating License, and Technical Specification requirements.
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No violations or deviations were identified in this area.
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4 Plant Startup from Refueling and Startup Testing On January 3,1987, a reactor startup was performed following a scheduled refueling outage..The reactor was critical'at 9:22 p.m. the same day.
The main turbine was p'i:ced into service on January 6,1987. The RI witnessed the unit startup to verify the following:
The control rod withdrawal sequence and rod withdrawal authorization
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were available and all surveillance tests required to be performed
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before the startup were satisfactorily completed.
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Startup was being performed in accordance with technically adequate
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and approved procedures that had been revised to reflect changes made to the facility during the outage period.
Startup activities were conducted in accordance with' requirements in
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the CNS Technical Specification.
The RI reviewed the following procedures prior to reactor startup:
General Operating Procedure (GOP) 2.1.1.1,'" Reactor Startup Review,"
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Revision 0, dated May 29, 1986 GOP 2.1.1.2, " Technical Specifications Prestartup Checks,"
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Revision 6, dated August 8, 1985
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The RI observed the-licensee's performance of the following procedures during reactor startupt GOP 2.1.1, " Cold Startup Procedure," Revision 26, dated December 29,
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b 1986 GOP 2.1.3, " Approach to Critical," Revision 11, dated September 18,
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1986 SurveillanceProcedure(SP)6.4.1.2,"WithdrawControlRod
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Operability," Revision 16, dated December 18, 1986 SP 6.4.1.3, "CRD Coupling Integrity Check," Revision 7, dated
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October 30, 1986 NuclearPerformanceProcedure(NPP)10.13,"ControlRodSequenceand
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Movement Control," Revision 15, dated October 30, 1986 NPP 10.16, " Shutdown Margin Evaluation, Attachment 3, Shutdown Margin
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Test (Critical) Data Sheet," Revision 14, dated October 16, 1986 The shutdown margin, core thermal power, core power distribution limits, and nuclear instrumentation calibration, were inspected and documented in NRC Inspection Report 50-298/86-36 paragraphs 3, 4, 5, and 6.
The RI
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conducted,addiUonalinspectionsintheseareasduringtheinspecticn
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'No violations or deviations were identified in this area.
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5.
Plant Trips-Safety Sys' Mm Challenges The NRC inspectors held discussions with operations _ shift personnel and reviewed control room records including log entries, recorder traces, and computer printouts associated with three unscheduled reactor scrams that
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occurred as follows:
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On January 4,1987, the reactor was in startup mode at approximately t
8 percent of rated power; Reactor heatup and pressurization were in progress. Reactor vessel water. level was being maintained using makeup flow from one condensate booster pump through the "A" Startup Flow Conhot; Valve, which was in automatic single element control.
The "B" Reactor Feedwater Pump (RFP) was placed into service and thought to he maintaining level through the "A" Startup Flow Control valve.- h sever, the isolation valve connecting the "B" RFP to "A" Startup Flow Control valve was shut. Reactor pressure eventually d
increased to, greater than condensate booster pump _ discharge pressure, and reactor' vessel level began decreasing. When the reactor low
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water level alarm was received, operators realized that isolation
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valve was shut and immediately opened it. When the isolation. valve opened, reactor feedwater flow rapidly increased because the "A"
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Startup Flow Control Valve was in the full open position as demanded by the reactor vessel water. level control system. The rapid injection of relatively cold feedwater caused reactor power to i
rapidly increase, resulting in the initiation of an APRM 15 percent High Flux Scram at 11:52 a.m.
No other safety systems were required
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to operate. Following the scram, normal water level was established using,"B" RFP. The reactor was restarted at 10:34 p.m. on January 4,
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On January 7,1987, _the reactor was in run mode at 25 percent of rated power.
Instrument and Control (I&C) personnel were performing voltage measurements to determine the reason for improper operation
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of the steam flow / feed flow recorder. When the voltmeter probes were placed on the feedwater flow signal terminal connector, one of the
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signal wires momentarily lost contact with the terminal connector
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because of loose terminal connector nut. This resulted in a loss of the feedwater flow signal to the reactor water level contrcl system.
The "A" RFP responded to the zero feedwater flow signal by increasing speed.
"A" RFP tripped shortly thereafter due to low suction pressure. Control Room Operators unsuccessfully attempted to place
"B" RFP into service. As a result, a low water level scram (+12.5 inches) occurred at 7:45 p.m.<before feedwater flow could be
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restored. Primary Containment Isolation Groups 2, 3, and 6 actuated
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at the low water level setpoint. The Standby Gas Treatment System d
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.7 automatically started on the Group 6 Isolation. The High Pressure Coolant-Injection (HPCI) and Reactor Core Isolation Cooling (RCIC)
systems pumps automatically (at -37 inches water level) started and
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restored water level to normal. No other safety systems were required to operate.
Prior to startup, I&C personnel sampled 482 terminal connectors for-loose terminal connections. The sampling included 261 terminal connectors affected by the Detailed Control Room Design Review (DCRDR) and 221 randomly selected control room console terminals. No loose terminal connections were identified. The
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reactor was restarted at 4:20 p.m. on January 9,1987.
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On January -10,1987, the reactor was in the run mode at 22 percent
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rated power. Control Room Operators were performing.drywell inerting.
activities, which increased nitrogen gas flowrate and consumption.
Inboard Main Steam Isolation Valves (MSIV) concurrently use nitrogen gas for operation. The increased demand for nitrogen gas resulted in a low nitrogen supply header pressure which was insufficient to maintain the MSIVs in the open position. Subsequently, all inboard MSIVs drifted shut producing a MSIV closure scram at 10:27 a.m.
Primary Containment Isolation Groups 2, 3, and 6 were actuated
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because the low water level setpoint (+12.5 inches) was reached when the reactor scrammed. The Standby Gas Treatment System automatically started on the group 6 isolation. No other safety equipment was required to operate. RCIC was started manually to control steam
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pressure and water level. The reactor was restarted at 8:27 p.m. on January 10, 1987.
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During the outage, the licensee completed Design Change (DC) 86-36,
"Drywell Nitrogen Supply Pressure Switch."Section X of DC 86-36 identified documents which required updates or changes. The documents listed included:
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l S0P 2.2.59 - Plant Air System
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S0P 2.2.60 - Primary Containment Cooling and Nitrogen Inerting System l_
Alarm Procedure 2.3.2.21A - Panel 9-3 - Annunciator 9-3-4 Section X of DC 86-36 did not specify General Operating Procedure (G0P) 2.1.1, " Cold Startup Procedure," as requiring change.
Post scram review of the event delineated in paragraph 5.c above identified that procedures 50P 2.2.59, S0P 2.2.60, and Alarm Procedure 2.3.2.21A required additional revision and procedure GOP 2.1.1 also required revision. Technical Specifications, paragraph 6.3.2.A, j
requires-that written procedures be established, implemented, and maintained for startup and operation. The failure of the licensee to do this after DC 86-36 is an apparent violation.
(298/8703-01)
The RI also noted that the failure to identify GOP 2.1.1 in DC 86-36 was similar to a violation cited in NRC Inspection Report 60-298/86-13.
Although licensee procedures required that design changes identify
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procedures requiring revision, GOP 2.1.1 was not identified in DC 86-36 as requiring change. This is an apparent violation.
(298/8703-02)
The NRC inspectors found that there had been classroom training of operators on DC 86-36, but this training did not address procedural changes or operational' effects of the change. The procedural changes were apparently covered by)providing the operators with a large reading file (several inches thick for self-study. Appendix A to CFR Part 55 requires that requalification training include training in facility design changes, procedure changes, and license changes, procedure changes, and license changes. This requirement is implemented through 10 CFR 50.54 and the approved requalification plan. The NRC inspectors recognized that the reading file approach to operator training can be effective for small changes or changes of limited scope. However, the effectiveness of this technique at the end of an outage when the reading file is several inches thick is questionable in theory and obviously not effective in this instance. This is an a) parent violation, but it is not cited because of the relief granted by tie Commission Policy to exercise discretion in selecting appropriate enforcement action for violations involving training.
It is therefore carried as an unresolved item (298/8603-03).
Two violations and one unresolved item were identified in this area.
6.
Operational Safety Verification The NRC inspectors observed control room operations, instrumentation, controls, reviewed plant logs and records, conducted discussions with control room personnel, and performed system walkdowns to verify that:
Minimum shift manning requirements were met.
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Technical Specification requirements were observed.
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Plant operations were conducted using approved procedures.
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Plant logs and records were complete, accurate, and indicative of
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actual system conditions and configurations.
System pumps, valves, control switches, and power supply breakers
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were properly aligned.
Instrumentation was accurately displaying process variables and
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protection system status was within permissible limits for operation.
When plant equipment was found to be inoperable or when equipment was
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removed from service for maintenance, it was properly identified and
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redundant equipment was verified to be operable. Also, the NRC inspectors verified that applicable limiting conditions for operation were identified and maintained.
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Equipment safety clearance records were complete and indicated that
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affected components were removed from and returned to service in a correct and approved manner.
Maintenance work requests were initiated for equipment discovered to
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require repair or routine paventive upkeep, appropriate priority was assigned, and work comenced in a timely manner.
The conditions of the plant and equipment such as cleanliness,
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leakage, lubrication, and cooling water were controlled and maintainea.
Areas of the plant were clean, unobstructed, and free of fire
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hazards. Fire suppression systems and emergency equipment were maintained in a condition of readiness.
Security measures and radiological controls were adequate.
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The NRC inspectors performed a lineup verification of the following systems:
High Pressure Coolant Injection System (HPCI)
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Core Spray Loops "A" and "B"
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The tours, reviews, and observations were conducted to verify that facility operations were performed in accordance with the requirements established in the CNS Operating License and Technical Specification.
Appendix R to 10 CFR Part 50 establishes requirements for fire protection.
One requirement is to position certain specified motor operated control valves to the design basis accident position, verify the position, and deenergize the circuit. This requirement ensures that in the event of a l
fire the valve will remain in its design basis accident position.
l Residual Heat Removal (RHR) valve RHR-M0-17, " Suction Cooling Outboard Isolation Valve," was positioned and then deenergized to meet Appendix R requirements. However, meeting the Appendix R requireirents caused RHR-M0-17 to be technically inoperable, because power was removed. CNS Technical Specification table 3.7.1 lists primary containment isol6 tion valves that must be operable during plant operation.
RHR-M0-17 and RHR-M0-18, " Suction Cooling Inboard Isolation Valve," are included in
table 3.7.1.
CNS Technical Specifications, paragraph 4.7.D.2, requires I
that if RHR-M0-17 becomes inoperable, then, the position of RHR-MO-18 shall be recorded daily. On January 6,1987, the SRI noted that RHR-M0-18, had not been recorded daily as required by Technical Specifications during the period January 3-6, 1987. This is an apparent
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However, the operability requirements found in Appendix R of 10 CFR Part 50 and the CMS
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Technical Specification are conflicting as noted above. This item will remain unresolved pending an NRC review and evaluation of the conflicting regulatory requirements.
(298/8703-04)
One unresolved item was identified in this area.
7.
Monthly Surveillance Observations The NRC inspectors observed Technical Specification required surveillance tests. Those observations verified that:
Tests were accomplished by qualified personnel in accordance with
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approved procedures.
Procedures conformed to Technical Specification requirements.
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Test prerequisites were completed including conformance with
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applicable limiting conditions for operation, required administrative approval, and availability of calibrated test equipment.
Test data was reviewed for completeness, accuracy, and conformance
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with established criteria and Technical Specification requirements.
Deficiencies were corrected in a timely manner.
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The system was properly returned to service.
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The RI observed the licensee's performance of the following surveillance tests and operating procedures on the indicated dates:
January 1,1987, SP 6.4.2.1, "RCIC Turbine Overspeed Functional
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Test," Revision 9, dated May 8, 1986*
January 1,1987, GOP 2.1.14, " Reactor Vessel In-Service Leak Test,"
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Revision 16, dated April 3, 1986*
l January 1,1987, NPP 10.9, " Control Rod Scram Time Evaluation,"
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Revision 14, dated November 6, 1986*
January 5, 1987, SP 6.3.3.1A, "HPCI Test Mode Surveillance Operation
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from ASD-HPCI Panel," Revision 0, dated November 13, 1986*
January 6,1987, S0P 2.2.14, "22 KV Electrical System," Revision 23,
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dated May 15, 1986 l
January 6,1987, S0P 2.2.77, " Turbine Generator," Revision 27, dated
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NPP 10.1, "APRM Calibration," Revision 16, dated
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January 9,1987, Special Procedure 86-13 " Primary Containment Inerting Without SGT," November 10, 1986 January 9,1987, GOP 2.1.15, " Reactor. Recirculation Pump Startup and
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Shutdown," Revision 18, dated' October 30, 1986 January 9,1987, SOP 2.2.28, "Feedwater System," Revision 39,
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The SRI observed the licensee's performance of the following procedures on the dates indicated below:
January 6,1987, SOP.2.2.14, "22 KV Electrical System," Revision 23,
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dated May 15. 1986 January 6.1987, S0P 2.2.77, " Turbine Generator," Revision 27, dated
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December 28, 1986 January 6,1987, SP 6.1.6, "MSIV Logic Functional Test," Revision 9,
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dated March 19, 1985 January 6,1987, SP 6.4.8.2.4, " Main Turbine Trip Test," Revision 8,
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dated February 13, 1986 January 9,1987, SP 6.3.10.5, "Drywell Pressure Suppression Chamber
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Vacuum Breaker Operation," Revision 19, dated September.19,1985 The reviews and observations were conducted to verify that facility surveillance cperations were performed in accordance with the requirements established in the CNS Operating License and Technical Specification.
On January 18, 1987, at 10:54 p.m., the licensee performed SP 6.3.5.2,
"RHR Motor Operated Valve Operability. Test," Revision 16, dated December 29, 1986. During the test of testable check valve RHR-A0V-68A, the indicator failed to indicate FULL'0 PEN.
The air-actuatoreposition indicator and the bypass valve (RHR-MO-274A) position indicator both indicated FULL OPEN. 'The failure to receive the FULL OPEN indication on the RHR-A0V-68A_ indicator resulted in concern-about the operability status of that valve. As a result the licensee submitted a justification for
continuedoperation(JCO). The licensee issued the JC0 on January 22,
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1987.- After reviewing the licensee's JCO, the NRC ~ issued a letter on January 23, 1987, allowing the licensee to continue operation.
j On January 27, 1987, a Group VI Containment Isolation Signal was area radiation monitors (y I&C technicians during surveillance testing of inadvertently initiated b i
RMA's). The isolation signal caused an automatic
l start of the' Standby Gas Treatment System and isolation of the secondary containment ventilation system. The technicians had incorrectly selected
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and then source tested the secondary containment exhaust plenum radiation detector which was not included in the surveillance test. The licensee terminated the test and restored the affected systems to normal. This will be an unresolved item because the inspection of all aspects of the cause had not been completed within the inspection period.
(298/8703-05).
One unresolved item was identified in this area.
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8.
Monthly Maintenance Observation
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The NRC inspectors observed preventive and corrective maintenance activities. These observations verified that:
Limiting conditions for operation were met.
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Redundant equipment was operable.
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Equipment was adequately isolated and safety tagged.
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Appropriate administrative approvals were obtained prior to
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commencement of work activities.
Work was performed by qualified personnel in accordance with approved
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procedures.
Radiological controls, cleanliness practices, and appropriate fire
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prevention precautions were implemented and maintained.
Quality control checks and postmaintenance surveillance testing were
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performed as required.
Equipment was properly returned to service.
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The SRI observed the licensee's performance of the following maintenance activities:
"C" Station Air Compressor
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Insulation replacement in ECCS pump. rooms
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These reviews and observations were conducted to verify that facility maintenance operations were performed in accordance with the requirements established in the CNS Operating License and Technical Specification.
No violations or deviations were identified in this area.
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Unresolved Item An unresolved item is one about which additional information-is required in order to determine if the item is acceptable, a violation or a deviation. The following unresolved items were identified during this inspection:
Item Paragraph Subject 298/8703-03
Personnel Training in the Area of Design Changes 298/8703-04
Appendix R Impacts Technical Specification Requirements 298/8703-05
Procedure Adequacy and Personnel Training in the area of Surveillance Procedures 10. Exit Interviews Exit' interviews were conducted at the conclusion of each portion of the inspection. The NRC inspectors sumarized the scope and findings of each inspection segment at those meetings.
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