IR 05000282/1992024
| ML20034G355 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 02/26/1993 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20034G351 | List: |
| References | |
| 50-282-92-24, 50-306-92-24, NUDOCS 9303090374 | |
| Download: ML20034G355 (17) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION 111 l
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Reports No. 50-282/92024(DRP); 50-306/92024(DRP)
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Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60 l
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Licensee:
Northern States Power Company
414 Nicollet Mall
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Minneapolis, MN 55401 Facility Name:
Prairie Island Nuclear Generating Plant f
Inspection At:
Prairie Island Site, Red Wing, MN
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Inspection Conducted:
November 23, 1992 through January 25, 1993
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l Inspectors:
E. R. Schweibinz, Team Leader
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M. L. Dapas D. C. Kosloff C. E. Brown
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R Bywater T. J. Kobetz J. H. Neisler
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i Approved By:
B.L.Jorgeke[ Chief
F3 Reactor Projects Section 2A Date Inspection Summary Inspection on November 23, 1992, through January 25, 1993 I
(Reports No. 50-282/92024(DRP); 50-306/92024(DRP))
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Areas Inspected: Announced team inspection by resident and regional s
inspectors to review, witness, and evaluate the licensee's ongoing activities
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relative to various modifications including the station blackout / electrical
safeguards upgrade (SB0/ESU) modification, the cooling water pipe i
modification, the reactor coolant system draindown modification, the Unit 1 Cycle 16 core reload modification, the independent spent fuel storage installation (ISFSI), controlled area entrance metal detectors, followup on j
previous inspection findings, licensee event report followup, and plant.
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restart activities.
j Results: No violations of HRC requirements were identified in the areas inspected.
Engineering personnel were actively involved in outage work
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activities, and in most cases did an excellent job.
For example, there were
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approximately 112 modifications, 3,400 work requests, and 68,000 individual wire manipulations that occurred during the outage, yet mistakes were
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infrequent and minor.
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b 9303090374 930226
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PDR ADDCK 05000282
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Persons Contacted J
- K. Albrecht, General Superintendent, Engineering l
T. Breene, Superintendent, Nuclear Engineering
M. Brossart, Nuclear Engineer
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- R. Cooper, Q. A. Engineer, PSQA
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- D. Dugstad, Engineer Associate E. Eckholt, Nuclear Support Services
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G. Goering, Manager, Nuclear Projects
- J. Goldsmith, SB0/ESU Project Manager P. Hellen, Plant Electrical Systems Engineer
- S. Hiedenian, System Engineer
- J. Hill, Supt. I & C Engineering
- C. Kinney, PSQA
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J Leveille, Licensing Engineer J. Maki, Superintendent Electrical Engineering
- T. McDaniel, Project Controls J. Mcdonald, Superintendent, Site Quality Assurance D. Mendele, Director, Quality Assurance i
H. Nelson, Superintendent, Prairie Island Core Analysis l
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R. Pearson, Superintendent, Steam Generator Systems R. Pond, SB0/ESU Project Electrical Engineer
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M. Reddemann, General Superintendent, Electrical and Instrumentation.
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Systems
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- G. Rolfson, General Superintendent Engineering - NPD
- M. Sellman, Plant Manager
J. Sorensen, Plant Scheduling and Services
- M. Thompson, SB0/ESU Projec'. Engineer
M. Wadley, General Superintendent, Operations
- E. Watzl, General Manager
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R. Woodling, Electrical Engineer
- E. Schweibinz, Senior Project Engineer,' Region III, U.S. Nuclear
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Regulatory Commission (NRC)
R. Bywater, Reactor Engineer, Region III, NRC l
M. Dapas, Senior Resident Inspector, Prairie Island, NRC
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T. Kobetz, Reactor Engineer, Region III, NRC D. Kosloff, Resident Inspector, Prairie Island, NRC-l C. E. Brown, Reactor Engineer, Region III, NRC
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J. Neisler, Reactor Inspector, Region III, NRC
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- B. Jorgensen, Chief, Section 2A, Region III, NRC
- Denotes those present at the management interview of January 22, 1993.
Other members of the licensee's staff and contract employees were also
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contacted during the inspection period.
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D5/06 Pro.iect (37701. 37828. 72701. 90712)
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a.
Work Quality Issues / Verifications (1)
Concrete Wall Crack Repair l
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During a previous inspection, the inspector observed a crack in
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the D5/D6 building G-wall near the junction with the turbine i
building. The licensee issued a nonconformance report to track
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and effect the necessary repairs. The inspector examined the i
repaired area and records of cube breaks to verify the compressive strength of the structural concrete mix used for the repair. Cube i
breaks exceeded 6,000 psi, well above the 4,000 psi design of the original concrete wall.
Based on visual observation' of the repair j
and results of the structural concrete cube breaks, the inspector
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concluded that the wall repair was acceptable.
i A crack in the 05/06 building floor on the 695 foot elevation near
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the crack in the G-wall was identified.
The licensee removed the i
concrete to the depth of the crack. The inspector observed that-l the crack stopped at the reinforcing steel indicating that it was i
caused by normal shrinkage of the concrete during the curing process and did not significantly degrade the strength of the l
concrete floor.
lq (2)
Transformer 21A Wirina
i The inspector observed that the poor workmanship evident in the l
taping of conductors with a damaged insulation jacket in i
transformer 21A had been reworked to an acceptable condition.
j Control wiring within the transformer cabinet had been anchored to i
the cabinet and the transformer and cabinet interior cleaned.
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RHR Pumo 22 Temporary Splice Replacement-l
The licensee had applied a temporary splice at the residual heat i
removal (RHR) pump No. 22 motor terminals. This temporary splice was not environmentally qualified (EQ). The pump has been
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reterminated with an Okonite splice kit. The component is located in a radiologically harsh environment but not in a harsh l
temperature or moisture environment. The inspector reviewed the i
environmental qualification of the Okonite splice kit and the
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plant EQ requirements for the RHR 22 pump. The splice kit was j
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qualified to 200 megarads and, according to the plant-EQ analysis,
the RHR pump is located in a 1-year post LOCA environment of less-j
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than 40 megarads.
Based on the data reviewed, the inspector
concluded that the splica kit is acceptable for use in this
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application.
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Design Issues (1)
05/06 Coolina System control Valve
I The inspector questioned whether.the thermostatically controlled
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three-way valves in the 05/D6 engine cooling systems would provide i
adequate control to preclude subfreezing (-30 F) coolant being
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supplied to the warm engines and oil coolers on diesel starts
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during severe cold weather. The licensee obtained valve data from the vendor including operating flow curves.
Review of the valve t
flow curves and vendor data indicated that sufficient mixing of
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warm coolant from the engine and cold coolant from the radiators L
would occur to preclude a slug of subfreezing coolant from
entering the engine or oil coolers.
During this inspection, in response to an NRC information notice on valves of this manufacture, the licensee was replacing the
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sensing elements in the valves with elements rated at a higher
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temperature.
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Emergency Diesel Generator low Temperature Coolina Thermostatic Elements
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The inspector attended a meeting between licensee representatives i
and the SACM Diesel representative.on the new D5 and D6 emergency
diesel generators (EDG) low temperature (LT) thermostatic control
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valves. The installed elements for the LT thermostatic valves
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were not the temperature range originally specified for the i
conditions at Prairie Island Nuclear Generating Plant (PINGP).
l The sensing element had a lower operating range than could be i
necessary to prevent damage to the element's temperature sensing
cartridge during operation in the hottest weather expected at i
Excessive temperature around the cartridge could cause the j
internal pressure -- from thermal expansion of the temperature
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sensitive wax -- to be excessive.
If the cartridge ruptures, the i
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wax would leak out and the thermostatic element would be j
inoperable. The licensee's investigation revealed that this
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specification had been changed by the manufacturer's engineering i
i group during installation after it was discovered that the wrong l
elements were installed. The change had been entered into the j
technical manual supplied to PINGP.
This change was due to j
miscommunication between different SACM engineering sections as to the ambient temperature range at PINGP.
Further investigation by
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the licensee showed the originally specified thermostatic elements
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to be the correct temperature range.
The licensee procured the
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correct temperature elements, and the inspector witnessed the
.j temperature element replacement in D6. The LT thermostatic
elements in D5 were to be replaced after Unit I core load. The I
licensee had initially investigated this problem in response to industry information about possible damage to thermostatic
elements due to excessive temperature.
The inspector considers a
this to be a good example of a prudent engineering decision.
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Establishing D5/06 and SB0 Equipment " Operable"
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Electrical Breaker Testina i
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The inspector witnessed relay and breaker testing for breaker 15-7
as part of electrical construction test (ECT) group testing prior
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to integrated safety injection (SI) testing.
The procedure was
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thorough, and the mechanic followed it closely.
Later, a mechanic
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was in process of testing the 2RY relay for breaker 25-16.
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procedure required that all trip relays be out prior to local manual trip testing. The mechanic was in contact with the control
room when he used a phase over-current test button to trip the 2RY relay vice tripping the breaker with the local manual trip.
This caused a lockout signal on bus 25 because breaker 25-16 is a
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f source breaker. The lockout signal is a normal reaction for a protective trip of a source breaker. This lockout signal caused a loss of power to bus 25 which caused an interruption of RHR flow.
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The mechanic immediately realized his mistake and notified the
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control room. The control room operators immediately restored
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power to bus 25 through breaker CT 12 after resetting the lockout
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Component cooling water (CCW) and RHR flow were restored after 24 seconds. The reactor head was removed and the refueling i
cavity flooded up at the time of the event. The inspector
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considered the decision to provide additional margin for shutdown t
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cooling prior to doing the electrical bus modifications to be
conservative and a good example of prudent shutdown risk
management.
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The incident was immediately reviewed by ECT and SB0 management.
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The ECT group was writing up a report on the incident and will l
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hold group meetings with all of the mechanics involved in ECT
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testing to pass along the information and lessons learned.
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SB0 engineers will write an NCR to go for " error reduction
action."
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05/D6 cJalification issues and Technical Soecification (TS)-
reouired surveillance testina The licensee received its TS limiting conditions for operation
(LCO) and surveillance requirements for the 5B0 Project in a l
license amendment dated December 17, 1992.
That was also the i
effective date of the new TSs.
Since both units were in cold
shutdown on December 17, 1992, none of the LCOs were applicable at
that time.
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The inspector attended meetings of the onsite safety review
committee during the week of December 28, 1992, where the licensee i
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reviewed the license amendment with regard to how surveillance j
test requirements would be met and whether preoperational testing i
of the new EDGs would be sufficient to satisfy TS surveillance
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requirements before plant restart.
The licensee intended to complete TS-required surveillance testing before restart or take
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credit for preoperational testing as meeting the TS surveillance testing to ensure operability. The " time clock" for TS surveillance periodicity would begin with the date of license amendment issuance (December 17, 1992). The licensee stated that there was historical precedence for this in that during initial plant preoperational testing, those tests would demonstrate operability of equipment and the TS surveillance time clock would start on the date of license issuance.
On January 7, 1993, the licensee was making preparations to heat up the Unit 2 RCS greater than 200 degrees Fahrenheit, a condition requiring the operability of D5 and D6.
The licensee's qualification program for D5 and D6, approved by the llRC, adopted commitments to perform tests specified in 14RC Regulatory Guide (RG) 1.9, Revision 2, RG 1.108, Revision 1, and IEEE Standard 387-1984. During an audit of the status of completion of 05 and D6 qualification program testing, the licensee questioned whether the preoperational tests, as performed, met the test requirements in the qualification program approved by the f4RC. The licensee inquired whether a temporary waiver of compliance, or some other means of regulatory relief, was necessary to continue with startup plans.
Specifically, the licensee's review found that the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> loaded runs of D5 and D6 did not completely meet test conditions committed to in RG 1.108. According to RG 1.108, the test should,
" Demonstrate the full load carrying capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, of which 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> should be at a' load equivalent to the continuous rating of the diesel generator,"
'(5400 kW for D5 and D6), "and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at a load equivalent to the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> rating of the diesel generator," (5940 kW).
The tests for D5 and D6, as actually conducted, consisted of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> operation at 75 percent load (4050 kW), followed by 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> at 100 percent load, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at 110 percent load.
Therefore, 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of operation were at 75 percent load instead of 100 percent load, and the total time of 100 percent rated load operation was 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> less than that specified in RG 1.108.
The licensee discussed this situation with the f4RC and considered making a request for relief from the RG 1.108 test conditions.
The licensee asserted that it could take credit for the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> loaded runs of D5 and D6 that were performed at the factory prior to installation at Prairie Island as meeting the qualification program requirements. Taking credit for the factory tests in-lieu-of explicitly meeting the site tests was found unacceptable by the NRC (discussions were held among the resident inspector office, Region Ill, NRR Projects, and NRR technical staff). This was principally because of the different purposes of the tests.
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Factory testing demonstrated the capability of the machine on a l
test stand, whereas site testing demonstrated qualification of the
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EDG system "in-situ" at the site.
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The NRC concluded that the licensee now had EDGs qualified to-i 75 percent of rated load (4050 kW), because the EDGs were not i
tested at 100 nercent load for the entire 22 hour2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> required test
.i duration.
Because 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the 22 hour2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> test period were at a-l reduced load of 75 percent, this was the maximum qualified rating l
of the EDGs.
i Regulatory relief in the form of a temporary waiver of compliance
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was not appropriate because performance of the TS-required
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surveillance testing was not due for 18 months.
Rather than a TS issue, this was a qualification issue (albeit of minor safety significance), because the EDG did demonstrate its function at
100 percent load for 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> and 110 percent load for 2 hop i
Additionally, the capability of each EDG is in excess of des basis accident (DBA) calculated loads.
Even at 75 percent lo ;
the power output would still be greater than the DBA loading.
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The licensee completed a safety evaluation (approved by the onsite
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safety review committee) documenting that the D5 and D6 EDGs were
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qualified to a load equivalent to 75 percent of rated load and i
that this qualification was sufficient for DBA loading conditions.
l Therefore, in an emergency and when called upon to perform their i
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safety function, the EDGs would not be challenged to conditions i
beyond that for which they were qualified.
The evaluated qualification would be contingent upon no increase in the analyzed i
DBA loading on the safeguards busses served by D5 and D6.
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With this evaluation completed, the licensee proceeded with f
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preparations for plant restart. Unit 2 was made critical on
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January 11, 1993.
In order for full qualification to 100 percent j
rated load to be obtained, the licensee must perform its first
J-18 month TS-required surveillance tests of D5 and D6 inclusive of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test specified in RG 1.108.
No violations, deviations, unresolved, or inspection followup items were l
identified.
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Coolina Water Pipe Modification (377011 l
The inspector examined ongoing work activities and completed work l
involving the cooling water piping replacement modification. Weld I
cladding was being deposited inside sections of pipe embedded beneath i
the old service building. Dbservation of voltage / current indication and
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deposition rates indicated that the cladding was being installed according to applicable specifications. Final clad thickness met or exceeded the 100 mil requirement.
Visual inspection of pipe butt joint
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fit-up and welding indicated that the pipe welds met the applicable
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codes and standards.
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I No violations, deviations, unresolved or inspection followup items were j
identified.
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4.
Reactor Coolant System Draindowr; Modification (37701. 72701)
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Desian The inspectors reviewed portions of the project description and i
safety evaluation for this modification and performed walkdowns of
the project in Unit I containment. A description of the
modification is presented in NRC Inspection Report 50-282/92022-
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50-306/92022. One area that the inspectors reviewed in particular
was the licensee's evaluation of the effects that the modification
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would have on the integrity of the reactor coolant system (RCS)
i and whether these effects would constitute an unreviewed safety
question (USQ).
In answering questions in its USQ determination.regarding any increase in probability of occurrence of evaluated accidents and
any reduction in safety margin, the licensee answered that the
increase in probability or decrease in safety margin, "is so small
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that this change is not considered an increase in probability," or t
a decrease in the margin of safety.
The inspectors examined the licensee's procedure for performing safety evaluations, N1ACD 5.6, Rev. O, " Safety Evaluations " This procedure provides the
licensee evaluator with guidance on how to address small changes
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in probability or safety margin.
For proposed activities (e.g.
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modifications) which may change the probability of an accident or
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change the margin of safety, figure 2 of N1ACD 5.6 provides l
instruction that very small or indeterminate changes in
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l probability or safety margin need not be considered.
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inspectors agreed with the licensee's conclusions regarding USQ
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determination for this modification.
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The inspectors also discussed with the licensee the issue of
hydrostatic testing of the RCS following the modification.
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Because this modification included RCS pressure boundary repairs,
a higher-pressure surveillance test than that normally performed j
.l after a refueling outage was required to be performed as per ASME
Code Section XI IWB-5200 Inservice Testing and. Inspection Program.
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The Code-required test pressure is equivalent to 102 percent.of-
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nominal 100 percent-power RCS pressure. At Prairie. Island, this
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pressure is 2280 psig.
The inspectors reviewed surveillance procedure SP 1174.20, Rev.
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" Reactor Coolant System Hydrostatic Test," and verified that the
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procedure had been revised to include the RCS draindown
modification piping and components in the defined hydrostatic test
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Installation l
During a routine tour of Unit I containment, the inspector examined the recently installed RCS draindown modifications.
l Water was leaking by the packing on valve RC-18-5 at an excessive i
rate.
The inspector reported the leak to a radiation protection
technician who took swipes of the area.
Followup on this the next
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day found that the area was not contaminated even though there was
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boron buildup on the valve body. A work order had been issued to
adjust the packing.
Further investigation revealed that all new valves are routinely repacked with PINGP preferred packing prior
to installation. There is a standard procedure to inspect all
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newly repacked valves at several points during pressurization.
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This probably would have caught the leak, however, the vessel head
was still off and the refueling cavity was flooded; therefore, the
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procedure had not been accomplished yet. The valve was leaking
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sufficiently at the low static head pressure to have boron
buildup.
The inspector also questioned the placement of the two i
communication line valves as being very hard to get to for
operation, especially from an as-low-as-reasonably-achievable
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(ALARA) radiation exposure view point.
Interviews with the system
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engineering group revealed that ALARA had been considered along
with the frequency of operation and valve orientation.
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Testina
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The inspector witnessed the performance of Installation and Test
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Procedure 362-033, " Testing of the newly installed hot leg drain i
path and proposed drain down procedure." All personnel involved
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l were thoroughly briefed on the procedure beforehand. All expected actions and possible consequences were discussed in detail.
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Personnel were stationed, communication was established, and the i
test was run from the control room in a good controlled manner.
Each step of the procedure was performed and the re;olts evaluated
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I prior to proceeding to the next step. The results were thoroughly documented, and the test was completed with no problems. The
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results of this test will be used to prepare the draindown
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procedure for use on subsequent Unit 1 outages.
The inspector
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j considered this test procedure to be well formulated and i
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performed.
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No violations, deviations, unresolved, or inspection followup items were i
identified.
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5.
Unit 1 Cycle 16 Core Reload Modification (37701. 72701)
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The inspector reviewed the project description, safety evaluation, and other documentation relating to the Unit I cycle 16 core reload
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modification.
The modification consisted of replacement of
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48 Westinghouse Optimized Fuel Assemblies with 48 fresh Westinghouse
High-Burnup Optimized fuel Assemblies.
The inspector provided some minor comments to the licensee regarding the Unit 1 cycle 16 reload
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safety evaluation and the October 1992 Monthly Core Performance Report.
These comments included:
a.
In the discussion, " Accident and Transient Analysis," of the safety evaluation, justification for using calculated results from previous operating cycles was not clearly identified. The inspector had to refer to another reference document to identify the licensee's written justification of the practice of using
" bounding results" from previous core analyses for application.to the current cycle.
b.
The Monthly Core Performance Report for the month of October 1992 identified that, "Both Units were base loaded throughout the month."
In fact, Unit I was offline from October 1 through 8, 1992, due to a short forced outage. Additionally, the dates that each unit was taken offline for the dual ~ unit outage were -
each incorrect by one day. These minor errors did not, however, result in errors in the calculation of fuel burnup for Unit 1 or Unit 2.
The results of the licensee's test procedure 030, " Post-Refueling Startup Physics Testing," showed that the startup physics testing predicted parameters were acceptable. The inspector discussed with licensee nuclear engineers the application of a bias in the calculation of the beginning-of-cycle, all-rods-out, hot-zero-power, critical boron concentration (CBC). The measured CBC in the last several startup physics tests for new cores has deviated from its predicted value, and in some cases by an amount greater than the 50 ppm boron review criterion.
A positive correlation has been observed between the number of gadolinium-doped fuel pins in the core and the amount of the CBC deviation from its predicted value. The licensee is continuing an investigation into the cause of the correlation.
No violations, deviations, unresolved, or inspection followup items were identified.
6.
Independent Spent Fuel Storaae Installation (ISFSI) (37701)
The licensee has completed the construction of the ISFSI safety related concrete pads. The inspector's visual inspection of the pads verified that the pads were installed according to applicable specifications and drawings.
The licensee's compression test cylinder breaks exceeded the 3,000 psi design requirements. Air entrainment -and slump tests were acceptable.
No violations, deviations, unresolved or inspection followup items were identified.
7.
Controlled Area Entrance Metal Detectors (71707)
The inspector questioned the metal detectors' calibration after noting a difference in sensitivity between adjacent detectors at.the entrance to
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the controlled area. After talking to the licensee security manager, the inspector witnessed the test of the metal detectors using a trial weapon. Two of three. metal detectors passed the test.
The third detector passed initially but failed after the inspector questioned the officer about removing all other metal from his person except the trial
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weapon. The detector then failed the test. The licensee immediately placed the metal detector out of service and set up to do a calibration on the detector.
The detector passed the calibration test later the same day and was returned to service. The licensee took additional action to ensure all security personnel were aware of the requirement to remove all extraneous metal from their person prior to performing the daily test of the metal detectors with a trial weapon.
No violations, deviations, unresolved, or inspection follow-up items were identified.
8.
Followup on Previous Inspection Findinas (92701, 37701)
a.
(Closed) Inspection Followup Item 50-282/92010-03:
50-306/92010-03: D5/D6 Starting Air System Independence.
During a previous inspection, documented in NRC Inspection Report 50-282/92010; 50-306/92010, the inspectors reviewed design and installation of the starting air (SA) system for the D5 and D6 EDGs. An inspection followup item was identified regarding the independence of the four subsystems of SA that serve each EDG.
The inspectors questioned whe'.her SA system independence had been compromised by the installatice of an air supply cross connection for the fuel rack stopping devices.
Upon further review., the inspectors noted that SA is interconnected to tne fuel rack stopping devices to each engine of the twin-engine EDGs but only between two of the SA subsystems at a time. That is, SA subsystems lA and 28 are inter-tied and
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subsystems IB and 2A are inter-tied.
This arrangement provides
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assurance that, in the event of failure of the hydraulic governor actuator on one engine (which could result in full rack overspeed)
the other engine will be shut down without dependence upon the electronic fuel shutdown solenoid.
Check valves are installed between the inter-tied subsystems for isolation and orifices allow
pressure to bleed off from the fuel rack stopping devices after EDG shutdown. The inspectors were satisfied that the interconnection between the SA subsystems in the above manner to inter-tie the fuel rack stopping devices on each side of the EDGs-does not comprise a potential common mode failure mechanism which could disable the SA system's safety function.
This item is closed.
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b.
(Closed) Inspection Followuo Item 50-282/92010-06:
50-306/92010-06: Starting Air System 24 Hour Drop Test.
During a previous inspection period, documented in NRC Inspection Report 50-282/92010; 50-306/92010, the inspectors identified an inspection followup item regarding unacceptable levels of SA system leakage during system prerequisite testing.
The inspectors noted in this inspection period that SA leakage problems had been corrected and system integrity achieved.
Additionally, the inspectors reviewed the results of prerequisite tests SB0-SA-505 and SB0-SA-605, "D5/06 Diesel Generator Starting Air Pressure Drop Test." This test provided verification that SA pressure in three out of four air receiver tanks was sufficient to permit a minimum of five attempted starts of the EDG for a minimum of five seconds cranking duration for each start. The tests were successful. With initial air receiver tank pressure at approximately the low pressure alarm setpoint, and the air compressors disabled, greater than ten engine cranking cycles of five seconds duration were performed for each EDG. This item is cl osed.
No violations, deviations, unresolved, or inspection followup items were identified.
9.
Licensee Event Report (LER) Followup (92701. 37701. 727011 a.
(00en) LER 306/92004, Auto-Start of D5 Diesel Generator Due To Personnel Error.
At 11:29 p.m. on November 25, 1992, the D5 EDG auto-started when construction electricians were working in safeguards racks connecting auto-start circuitry for the new EDG, The LER that the licensee submitted was a voluntary report. The D5 EDG was not technically an " operable" engineered safety feature; its installation and turnover to plant operations was not complete.
However, some of the circumstances surrounding the event are of some concern. The electrician foreman supervising the-work activity left the work site to respond to a page at another location. The foreman was responsible at the time for the work activities of nine electricians in various areas (which, the inspectors learned, is not unusual practice for the licensee).
While the foreman was away, he forgot to contact the control room to request that operators perform procedural steps before the electrician continued cable terminations.
These procedural steps would have prevented the D5 EDG from auto-starting.
While the foreman was away, the electrician proceeded with the cable terminations using a copy of a portion of the original work request; the foreman had the original. Although the electrician was informed at a pre-job briefing that control room notification would be made by the foreman and was necessary to prevent EDG
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I Operators were not aware that the EDG had been running until the l
foreman notified the control room of the error. The annunciator I
alarm that would have alerted the operators to the EDG auto-start was not in service because of modification work.
The emergency response computer system (ERCS) alarm, received as a line of.
information on a printer, was received but was not observed by the operators.
The licensee's corrective actions for this event included an
immediate safeguards rack work stoppage to discuss the event with l
workers and supervisors, providing training to electricians on the importance of clear communications when completing procedural steps, modifying the ERCS to improve operator identification of EDG alarms, and completion of the annunciator panel modifications.
The inspectors will evaluate the adequacy of these corrective actions in a future inspection.
b.
(0 pen) LER 282-92017: December 30, 1992, Unit 1 Component Cooling (CC) nump automatic start.
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At 3:13 p.m. (CST) on December 30, 1992, No. 12 Component Cooling (CC) pump automatically started on low discharge header pressure when motor-operated valve MV-32120 (11 CC heat exchanger outlet crossover isolation valve) was inadvertently shut. This LER was submitted by the licensee as a voluntary report. This " voluntary" aspect is still being reviewed by the inspectors.
c.
(Closed) LER 306-93001: January 4,1993, Unit 2 Component Cooling (CC) pump automatic start.
At 10:48 p.m. (CST) on January 4, 1993, No. 22 Component Cooling (CC) pump automatically started on low-pressure in the CC system.
While switching residual heat removal (RHR) trains in accordance
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with Operating Procedure 2015, " Residual Heat Removal System,"
l motor-operated valve MV-32129 (22 RHR heat exchanger CC inlet
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valve) was opened increasing the CC system flow. This resulted in a lowering of system pressure and automatic start of the standby l
CC pump, No. 22. Operating Procedure 2015, " Residual Heat Removal-System," was revised and a precaution was added to alert the operators to the need to start the standby pump prior to CC valve operations.
This LER is closed.
No violations, deviations, unresolved, or inspection followup items were
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identified.
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10.
Plant Restart (37700. 61726. 62703. 71707. 92701)
i a.
Startuo i
The inspectors observed portions of the heatup and the reactor startup of Unit 1 and Unit 2.
The inspectors also attended the pre-evolution brief. The licensee used the dilution to criticality method of startup for both units, and subsequently
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performed core physics testing on Unit 1.
Procedural guidance for diluting to criticality is contained within the procedure for core physics testing. There is no dedicated procedure for diluting to
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criticality separate from core physics testing.
There is also a l
specific procedure _ for conducting a reactor startup involving a j
l rod pull to criticality. Since the licensee did not intend to perform core physics testing on Unit 2, it had to combine existing startup procedures to ensure operators had sufficient procedural guidance to conduct the corresponding Unit 2 reactor startup.
The inspectors reviewed the revised procedures to support Unit 2 reactor startup and concluded that they provided adequate guidance. The inspectors observed that the startup of both Units was well controlled.
On January 11, 1993, the licensee determined that there was l
leakage from the Unit 1 inner reactor vessel 0-ring seal.
The inspectors observed the licensee's Operations Committee (onsite review committee) discussion of this condition and their decision to continue operation relying on the outer seal, with the leak i ~
detection system aligned to detect leakage _ from the outer 0-ring seal.
b.
Containment Closeout Inspection The inspectors accompanied the licensee during the closeout inspection of Unit 1 annulus and containment and Unit 2 containment (SP 1750, " Post Outage Containment Closeout," both
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units). The inspectors did not identify any concerns.
c.
Surveillance The inspectors reviewed Technical Specification required surveillance testing as described below, and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, and Limiting Conditions for Operation were met. The inspectors further verified that the removal and restoration of affected components were properly accomplished, test results conformed with Technical Specifications and procedure requirements, test results were reviewed by personnel other than the individual directing the test, and deficiencies identified during the testing were properly reviewed -
and resolved by appropriate management personnel.
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Portions of the following test activities were observed or reviewed-
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(1)
SP 1100, "12 Motor Driven Auxiliary Feedwater Pump Monthly
Surveillance."
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SP 1174.20, " Unit 1 Reactor Coolant System Hydrostatic
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Test."
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(3)
SP 2046, ' Rod Drop Test."
d.
Followun of a concern identified durino observation of the Unit' 2
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Intearated Safety Iniection Test.
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The licensee identified ice blockage in the AFW pump recirculation l
line to the condensate storage tanP (CST) during the performance i
of the Unit 2 integrated safety injection test.
Ice formed in the
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line when the associated heat trace ciruit was de-energized for r
maintenance. As a result, No. 21 motor-driven AFW pump ran in a
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dead-headed condition for approximately 16 minutes. The subject
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ecirculation line to the CST also provides a rcturn path for cooling water from the AFW pump skid mounted, lube oil-cooling heat exchanger.
This recirculation line and cooling water return j'
path is common to both the motor-driven and turbine-driven AFW pumps. The inspectors raised a concern regarding the impact of blockage of the non-safety related (QA level III) recirculation line on AFW pump operation.
The licensee stated that it would
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review this issue to determine its potential safety significance.
.i Arrangements were made for the inspectors to evaluate the. results
of the licensee's review as part of their continuing inspection.
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Reactor Trio
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At 3:35 A.M. (CST) on January 8,1993, a reactor trip signal was l
generated on Unit 2 due to high source range flux. The indicated
bigh mm condition occurred on source range instrument channel
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N32 and caused an actuation of the reactor protection system (RPS)
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and also caused the reactor trip breakers to open. All rods were
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inserted at the time of the event.
The licensee initially
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suspected that the indicated high flux condition was caused by
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instrument noise induced from the large heeters that were being
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used to support steam generator crevice flushing. However, the licensee was nnt able to determine the root cause for the RPS
actuation, and therefore replaced the source range instrument.
l The inspectors reviewed the results of the licensee's root cause investigation and verified that the new source range instrument was providing an accurate indicatien of reactor potter during. the i
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Unit 2 startup. This actuation of the reactor protection system was not reportable per the recent r.* vision of 10 CFR 50.72 which
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took effect October 13, 1992.
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Maintenance Observation
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i Routine preventive and corrective maintenance activities were
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observed to ascertain that they were conducted in accordance with r
approved procedures, regulatory guides, industry codes or
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standards, and in conformance with Technical Specifications. The i
following items were considered during this review:
adherence to l
Limiting Conditions for Operation while components or systems were
removed from service, approvals were obtained prior to initiating
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the work, activities were accomplished using approved procedures j
and were inspected as applicable, functional testing and/or
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calibrations were performed prior to returning components or t
systems to service, quality control records were maintained, activities were accomplished by qualified personnel, radiological
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controls were implemented, and fire prevention controls were i
implemented-I Portions of the following maintenance activities were observed or reviewed during the inspection period:
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(1)
Operation of D5 and D6 Emergency Diesel Generators (EDG) to
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i verify cause of an EDG trip that occurred when removing the EDG from service.
(2)
Operation of D5 and D6 EDGs to establish proper setpoints i
for undervoltage (UV) relays.
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Obtaining current measurements from newly installed current -
f transformers on No. 12 Auxiliary Feedwater Pump motor.
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(4)
Calibration of Bus 15 UV relays.
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No violations, deviations, unresblved or inspection followup items were identified.
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11.
Manaaement Interview (71707)
The team leader mat with the licensee representatives denoted in paragraph 1 on January 22, 1993. Additional debriefing meetings had i
been held with licensee representatives at the conclusion of each
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inspection window. The scope and findings of the inspection were
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discussed, as described in these " Details." During this meeting, the
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licensee was asked whether any documents or processes inspected were
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proprietary. None were identified.
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