IR 05000285/1990026
| ML20055C794 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 06/15/1990 |
| From: | Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20055C791 | List: |
| References | |
| 50-285-90-26, GL-88-17, GL-89-08, GL-89-8, IEB-85-003, IEB-85-3, NUDOCS 9006250136 | |
| Download: ML20055C794 (16) | |
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APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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LRC Inspection Report:
50-285/90-26 Operating License:
DPR-40 Docket:
50-285 Licensee: Omaha Public Power District (OPPD)
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444 South 16th Street Mall Omaha, Nebraska 68102-2247
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Facility Name:
Fort Calhoun Ste. tion (FCS)
Inspection At:
FCS, Blair, Nebraska inspection Conducted: April 16 through May 12, 1990 Inspectors:
P. Harrell, Cenior Resident Inspector T. Reis, Resident Inspector
%yhs 'EI, Project Section C
C Approved:
gW1rttfri of Reactor Projects Mir-Cfit ef Date
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Inspection Summary Inspection Conducted April 16 through May 12, 1990 (Report 50-285/90-26)
i Areas Inspected:
Routine, unannounced inspection of previously identified
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items; orarational safety verification, monthly maintenance, surveillance,
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security, and radiological protection observations; onsite followup of events; and in-office twiew of reports.
Results: Two noncited violations are documented in the enclosed inspection report. They involve:
Failure to comply with quality assurance plan requirements to document and report deficiencies (paragraph 5,a and 5 b).
-Failure to revise a safety analysis as required by procedures for a field change to a design modification (paragrapn 5.c).
The noncited violations were identified during inspection of maintenance and surveillance activities. Within the remaining areas, it appeared that the licensee's actions met the appropriate regulatory requirements.
Summaries are provided below.
l 9006250136 900618 PDR ADOCK 05000?85-Q PDC
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2-During the performance of a hydrostatic test on a safety-related portion of the chemical and volume control system, the licensee temporarily abandoned the test with the piping full of fluid, isolated, and unvented with an active heat input from its boric acid heat tracing. The condition could have potentially overpressurized the low pressure piping.
Contrary to quality assurance plan (QAP) requirements, the event was not promptly reported so as to ensure appropriate evaluation.
During the performance of a new ptocedure designed to transfer 120-Vac vital instrument loads, a malfunction occurred causing momentary loss of power to the instruments and actuation of the diserse scram system. Again, the condition was not reported to ensure appropria*.e evaluation.
The licensee changed plant conditions via a field change to an emergency diesel generator (EDG) modification without reanalyzing the safety evaluation applicable to the modification.
The inspector found the licensee Technical Specifications (TS) relative to electrical power requirements in the depressurized, reduced inventory mode of operation to be less conservative than most other licensees.
Specifically, the TS would allow shutdown coosing with midloop operation to proceed with no EDGs available, whereas later licensed plants require at least one emergency power source and one offsite source to be operable. The licensee realizes this vulnerability and conservatively maintains administrative controls to keep appropriate power sources available during reduced inventory modes of operation, i
The licensee identified a significant example of an equipment lineup and danger-tag error.
Equipment was found to be mispositioned from its danger-tagged position.
Since this was a repetitive occurrence, the licensee has change its procedure to require an independent verification for each tag-out performed.
The licenste caused damage to the reactor vessel head, control rod drive mechaniam ripper fingers, and alignment pins while attempting to reinstall the head. The licensee has concluded the root cause of the event to be incorrect judgement by personnel of the distance between the head and alignment T. ins during the lowering process. The incorrect judgement is the direct result of inadequate procedural guidance, i
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DETAILS 1.
Persons Contacted OPPD
- R. Andrews, Division IDnager. Quality and Environmental Affairs J. Bobba, Supervisor, Radiation Protection
- J. Chase, Manager, Nuclear Licensing and Industry Affairs M. Core, Supervisor, Maintenance
- S. Gambhir, Division Manager, Production Engineering
- W. Gates, Division Manager, Nuclear Operations
- R. Jaworski, Manager, Station Engineering
- L Kusek, Manager, Nuclear Safety Review Group R. Lisowyj, Special Services Engineer
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- D. Matthews, Supervisor, Station Licensing S. Miller, System Engineer
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S. Morales, Special Services Engineer
- W. Orr, Manager, Quality Assurance and Quality Control
- G. Peterson, Manager, Fort Calhoun Station
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J. Sefick, Manager, Security Services R. Short, Supervisor, Special Services Engineering
- C. Simmons, Station Licensing Engineer
J. Tills, Assistant Manager, Fort Calhoun Station D. Trausch, Supervisor, Operations
- Denotes attendance at the monthly exit interview.
The inspectors also contacted other plant personnel.
2.
Plant Status Immediately preceding this inspection period, the reactor plant was in a refueling status with the core offloaded to the spent fuel pool (SFP).
The SFP was cooled by an approved temporary system as both raw water (RW)
and component cooling water (CCW) systems were out of service for major valve work.
The shutdown cooling system ($DC) was restored on April 14, 1990, and transfer of fuel to the core began April 15, 1990, and was completed on April 16,1990. On April 22, 1990, the reactor vessel water level was reduced to facilitate head installation.
Due to problems encountered in head installation, the vessel water level remained at a reduced inventory until May 1,1990.
Simultaneously, EDG 1 was considered available for use but not operable due to its fuel oil transfer pump replacement. On April 24, 1990, EDG 2 was taken out of i
service for its scheduled inspection and overhaul, i
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The inspection period concluded with the reactor vessel head installed and
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tensioned and the control rods coupled.
3.
Review of Previously Identified Items (92701 and 92702)
I a.
(Closed) Open Item 285/8803-04i Testing of the Alternate Shutdown
i Psnel (ASP)
This item involved the lack of testing of the ASP.
After a review by the Office of Nuclear Reactor Regulation (NRR), it was dotermined
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that the TS should be amended to add testing requirements.
As a result of the issuance of a TS amendment request, issued on October 27, 1989, NRR issued Amendment 125 to the TS to require ASP i
operability and testing.
i Based.on the issuance of the TS amendment, this item is considered closed.
b, (Closed) Unresolved Item 285/8909-09:
Review of Chiculation for Individual Walking on Steam Line
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This item was related to the potential for overstressing the steam
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supply line for the auxiliary feedwater pump, due to an individual walking on the line while painting plant equipment.
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The licensee performed a calculation (ES-89-09) to verify that the line was not overstressed due to the weight of the individual.
NRR reviewed the calculation and stated that it did not appear that the piping was overstressed.
c.
(Closed) Open Item 285/8913-02:
Seismic Qualification of i
Valve HCV-1388B l
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This item involved the installation of Valve HCV-138SB, a steam.
generator blowdown valve.
It appeared that the valve qualification
was questionable 'since a support was not installed on the valve operator.
The licensee submitted a calculation to verify that the valve was qualified.
The calculation was reviews' by NRR and, in a letter dated March 27, 1990, verified that the u sta11ation was adequate, d.
(Closed) Open Item 285/8922-06: MOVATS Testing of Valve HCV-308
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Valve HCV-308, a cross-connect from charging pump discharge to the high pressure saf.ity injection (HPSI) header, used for post-LOCA hot
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leg injection, was the last safety-related valve which required testing per IE Bulletin 85-03, " Motor-0perated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings."
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it was successfully reset and tested during this refueling outage,
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and the results were satisfactory.
4.
Operational Safety Verification (71707)
a.
On April 23, 1990, EDG 2 was taken out of service for its scheduled refueling inspection and overhaul. At the time, EDG 1 was available for use but was not operable as defined by TS.
It had a temporary, nor, safety-related, fuel oil transfer pump in service while the normal ones were being replaced.
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The inspector reviewed the testing data performed on EDG 1 since it i
was returned to service from its refueling inspection and overhaul.
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Although it could not achieve a defined operable status because of the temporary fuel oil transfer pump, the test data indicated that the
EOG could reliably serve its inte: 1ed safety function.
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TS 2.1.1 allows both EDGs to be inoperable when reactor vessel water level is less than 15 feet above the top of irradiated fuel.
Licensee Operating Procedure OP-6, " Hot Shutdown to Cold Shutdown and Conduct of Shutdown Cooling Operations " requires, however, for these conditions that one EDG be available but not necessarily operable.
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Available is defined in OP-6 as ready to use within a short enough time to roet the intended need.
The OP-6 definition of available was taken verbatim from NRC Generic Letter 88-17, " Loss of Decay Heat Removal." Further, the licensee demonstrated that when OP-6 requires a diesel to be available, it also requires that it be " Caution Tagged" to prevent it from being taken out of service for additional maintenance.
In conclusion, it appears that the licensee manages offsite and emergency power sources in a conservative manner.
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b.
NRC Inspection Report 50-285/90-13 documented that commercial grade, unqualified hoses, manufactured by the Crawford Valve Company, had been purchased by the licensee and ma, have been installed in safety-related systems. The licensee g rformed a review of the installation of the hoses and provided the fol1 ~ing information:
Three purchase orders had been issued for 16 hoses.
- Thirteen hoses were found in the warehouse and had not been installed. All but one hose was designated for a safety-related system.
- Three hoses were installed in the flow system for the third, nonsafety-related, auxiliary, feedwater pump currently under construction. The hoses were removed and replaced with qualified hoses.
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All 16 hoses have been stored in the warehouse and identified
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with a material nonconformance tag.
- All hoses used on the emergency diesel generators were verified to be fully qualified.
The licensee's response to this issue was timely to ensure that nonqualified hoses were not installed in safety related systems.
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c.
During this inspection period, the inspector observed that the licensee was in the process of extensive investigation of secondary plant pipe wall thinning due to erosion and corrosion.
The licensee began its crosion/ corrosion control program in 1987.
The program is based on EPRI and NUMARC guidelines.
In July 1989 the licensee responded to Generic Letter 89-08, " Erosion / Corrosion-Induced Pipe Wall Thinning," indicating that the program it had in place plus scheduled enhancements ensured that erosion / corrosion will not lead i
to degradation of single phase and two phase, high-energy, carbon steel piping systems.
The licensee uses as its replacement criteria, a procedure developed i
by EPRI and contained in EPRI Report NP39-44 of April 1985.
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Essentially, the wear is determined from using nominal wall thickness as the baseline.
Next, the wear rate is determined by dividing the number of operational hours into the wear value. The time to minimum wall is determined by dividing the wear rate into the margin to minimum wall. This time is then halved for conservatism.
The resulting value is termed the inspection index and is expressed in
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terms of the number of operational cycles remaining.
The licensee is currently replacing or repairing all components which indicate an
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inspection index of two or less.
For the current refueling outage, the licensee chose 113 areas on l
which to perform 100 percent ultrasonic mapping.
In 1987 and 1988,
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188 and 104 areas, respectively, were examined.
During these outages, 18 and 14 areas, respectively, required replacement.
The number of areas inspected is significantly higher than the EPRI guidelines. The licensee desires to obtain baseline data from which to compare future measurements.
Of the 113 areas inspected, 8 failed to meet the acceptance criteria established by the licensee.
Of the 8, the only commonality to them was that they were encountered in areas where a flow restriction existed. The most significant degradation occurred in the main l
feedwater piping in the vicinity of Flow Control Valves FCV-1101 and FCV-1102.
In these areas, the process flowstream reduces from 16-inch nominal to 8-inch nominal, proceeds through the control valve, and then reverts to 16-inch nominal.
The apparatus was
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installed as a modification in 1983 to improve flow control.
After five operational cycles, it has eroded to the point of requiring
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repair.
The licensee has initiated an engineering assistance request to evaluate changing the design due to this erosion problem.
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d.
On April 26, 1990, the licensee informed the inspector of some manually operated valves found to be mispositioned during the I
performance of a hydrostatic test.
They were found by a special
services engineer performing an independent walkdown of the system.
i The independent walkdown was not procedurally required.
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Immediately, the supervisor-operations had the governing Procedure 50-0-20. " Equipment Tagging," revised to require that all equipment tag-outs be independently verified by an operator. Along with the procedure revision, a danger tag independent verification form (FC-20) was developed to be used and filed concurrently with the original tag sheet.
The licensee provided training to all operations personnel on the revised tag-out procedure. The inspector attended one of the' training
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sessions on April 28, 1990, and found the revised requirements to be understood by the operations staff.
The inspector interviewed the auxiliary building operator responsible for the errors.
Although he offered no excuse for the errors, he and other. operations personnel expressed a human factor concern with the tags.
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The licensee is in transition from a manual tap-out system to a computer assisted one.
The new computer printed tags, which were involved in the incident, contain significantly more information than the former manual tags.
The component identification and required position are not clearly differentiated from the remaining information which is not pertinent to the operator's task.
Licensee management likewise recognized this human factor component i
to the tagging problem. As an interim measure, the licensee, through the computer software, has the component identification and required position printed in boldface.
It appeared the licensee was prompt, conservative, and thorough in correcting the problem, 5.
Monthly Maintenance and Surveillance Observations (62703 and 61726)
a.
On April 28, 1990, while observing control room activities, the j
inspector witnessed a momentary loss of power to safety-related,
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120-Vac, Instrument Buses B, B1, D, and 01.
The loss of power resulted in the activation of the diverse scram system (DSS).
The reactor trip breakers, however, were already open because of the plant status.
Normally, under these plant conditions, the occurrence would have resulted in activation of the pressurizer pressure low J
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signal (PPLS), a reactor protection system (RPS) signal. However, PPLS was manually blocked.
Investi0ation by the licensee and the inspector found the cause to be an anomaly which occurred during the performance of prerequisites to i
Maintenance Procedure EM-RR-EX-0803, " Electrolytic Capacitor Replacement for Instrument Inverter D."
To perform the maintenance on the D Inverter, the loads en Buses D and D1 required transfer to Inverter B.
Normally, the licensee accomplishes this by stripping all the loads from the affected buses, opening the inverter output breaker, closing the B and D bus crosstie breakers, and then
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individually reloading the energized bus.
i For this outage, however, the licensee developed procedures to
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transfer more efficiently through a hot bus transfer method.
The licensee had planned to incorporate the methodology into its at power
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operational procedures.
Here, the buses to be crosstied are paralleled through their respective inverters in the bypass mode, the crosstie breakers are closed, and the output breaker from the inverter to be serviced is opened.
The procedure did not work as designed as power was momentarily lost to the buses.
The licensee
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believes that the problem arose from a phase angle differential between the two sources placed in parallel.
Subsequently, the inspector reviewed the completed maintenance
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procedure and work package and found no documentation of the incident.
Further, no incident or corrective action report was initiated.
From discussions held with senior engineering staff, however, it was apparent they were well aware of the occurrence and had already decided to abort placement of the methodology into the at power operational procedures.
b.
On April 23, 1990, the inspector observed performance of Procedure SS-ST-CH-3010. " Charging Pump Suction Header 10-Year Hydrostatic Test." In review of the official test record, the inspector observed that the special services engineer had noted that on April 21, 1990, the test was temporarily suspended at approximately 9 p.m. for the evening.
The next day at 6:30 a.m., the engineer realized the system was left water solid with no vent path and the boric acid heat tracing energized. The design rating of the pipe is 150 psig.
The engineer immediately notified the shift supervisor, who had the piping vented. The operator who vented the system reported that nothing-came out of the relief when it was vented.
The special
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services engineer ther walked down the affected piping and noted no damage.
No incident or corrective action report was generated.
The preceding was the full extent of the documented evaluation.
Further investigation revealed that prior to the inspector's questioning, the appropriate levels of management were verbs 11y i
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From statements received by the inspector, shift supervisor, lead special services engineer, outage coordinator, and plant manager were informed on the morning of April 22, 1990. The lead special services engineer has stated that an incident report was. required and that he had assumed his personnel had initiated one.
Further, the plant manager and lead special services engineer have indicated that the situation was very much an area of concern the
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morning of April 22, 1990, but after discussions with those involved, they were assured an overpressurization had not occurred.
Subsequent to the inspector's questioning, Incident Report 900215 was generated.
In response, system engineering properly evaluated that t
due to the. leakage past the hydrosti..ic test boundarie: experienced
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on April 21, 1990, and the fact that the system configuration was not changed, the system could not have been.overpressurized.
Further, the plant review committee (PRC) required, as corrective action, that all hydro procedures involving systems which are heat traced be
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revised to add a precaution to prevent inadvertent e
overpressurization.
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The FCS QAP, Section 10.4, which implements Criterion XVI of Appendix B to 10 CFR 50, states, in part, that conditions adverse to quality shall be promptly documented and brought to the attention of'
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the responsible manager and the manager quality assurance anti quality control.
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The QAP defines a deficiency as a condition or characteristic which, l
if left uncorrected, could become a significant deficiency.
The incide * involving momentary loss of power to the vital instrument tuses constituted a deficiency.
Procedure EM-RR-EX-0803, which the licensee had planned to incorporate into at power operational procedures, or the associated hardware, must be considered deficient.
If left uncorrected, an inadvertent actuation of engineered safeguards features (ESF) would result.
The incident involving the potential overpressurization of the charging pump suction header constituted a deficiency in that:
Procedure SS-ST-CH-3010 provided no instructions to vent the system in the event the test was postponed once initiated.
If left uncorrected, it or similar procedures could cause repetition of the event.
- The evaluation documented in the test record was inadequate in that it did not prove that the system was not overpressurized.
Normally, a Notice of Violation would be issued for the two examples of noncompliance with the QAP.
However, the violation is not being cited because the criteria specified in Section V.A of the Enforcement Policy were satisfied.
Specifically:
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The safety significance of the hot bus transfer event in the refueling mode of operation is minimal.
- The charging pump suction header was ultimately proved not to
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have been overpressurized.
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For both events, the intent of the regulatory and QAP requirements was satisfied. Appropriate levels of management i
were verbally informed of the occurrences, and evaluations, although undocumented, were made.
- The ifcensee initiated appropriate corrective action prior to the end of the inspection period.
On May 15, 1990, the FCS manager issued a memorandum to all station personnel reminding them of the requirements to document and report conditions adverse to qualify.
Further, the licensee has committed to reinforce the concept through general employee training (GET).
c.
In conjunction.with the inspector's investigation into the licensee's handling of power sources during reduced inventory modes of operation as described in paragraph 4 of this report, the inspector found that the licensee violated its own procedures by allowing EDG 1 to be available, but not operable, prior to removing EDG 2 from service.
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During this outage, the licensee performed Modification MR-FC-89-051,
" Replacement of Emergency Diesel Genarator Fuel Oil Transfer Pumps,"
The original plan called for having EDG 2 i
operable, performing the modification on EDG 1, proving EDG 1 operable, then removing EDG 2 from service for overhaul, Problems were encountered in the postmodification testing of the fuel oil transfer pumps which p_revented EDG 1 from being declared operable. A temporary fuel oil transfer pump was installed and engineering declared the diesel available.
The licensee issued Field Change FDCR 90-551 *.o Modifica-tion MR-FC-89-051.
The field change allowed EDG 2 to be removed from service prior to EDG 1 being returned to operable status. This clearly changed plant conditions as set forth in the original safety evaluation in that it allowed both EDGs to be inoperable simultaneously.
The original safety evaluation required EDG 1 to be
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operable prior to removing EDG 2 from service.
The safety evaluation
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was not revised to reflect the new condition.
As discussed in paragraph 4.a. however, TS 2.1.1 does allow both EDGs to be inoperable under these conditions.
License Procedure 50-G-7, " Operating Manual," implements American National Standards Institute (ANSI) Requirement 5.1.2 in stating, "It is the responsibility of every individual performing activities at Fort Calhoun Station to follow procedures exactly as written. Strict
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adherence to all procedures is absolutely required."
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1.icensee Procedure S0-G-21,Section III, paragraph 3.2.1 states, in
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part, that for field changes to modification design documents the design engineer shall review the proposed change to determine if the
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safety evaluation prepared for the modification will require revision.
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The situation was discussed with operations and system engineering.
The system engir.eer realized the error and promptly had the safety evaluation revised.
This appears to be an isolated incident of noncompliance in this area and the revised safety evaluation
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constitutes adequate corrective action.
Normally, a Notice of Violation would be issued for the procedural
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noncompliance. However, the violation is not being cited because the criteria in Section V.A of the NRC Enforcement Policy were satisfied
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in that the event was of minor safety significance and isolated and the licensee took prompt and effective corrective action.
6.
Security and Radiological Protection Observations (71707)
a.
On May 5, 1990, the inspector was notified of an unplanned
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l radiological exposure exceeding licensee administrative limits.
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pipe fitters and an accompanying radiological protection technician r
entered the lower cavity for purposes of installing the transfer canal flange. The area had been previously surveyed ar.d deemed a very high radiation area. As such, the fitters were each appropriately outfitted with an integrating alarming dosimeter, and a thermoluminescent dosimeter placed on that portion _of the whole body was expected to receive the most dose.
In this case, that was the i
upper thigh.
The workers were also outfitted with extremity
monitoring, self-reading dosimeters. The integrating alarming
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I dosimeters were programmed to alarm at 500 mr.
Upon exiting containment, it was discovered that the self-reading dosimeters of the craftsmen were off scale. One integrating alarming dosimeter had alarmed, which was the reason for departing the job site.
The thermoluminescent cosimeters of the individuals were pulled and read with results indicating 1216 and 1220 mr received. This dose brought the accumulated whole body dose for the individuals involved to 1327 and 1366 per calendar quarter, respectively.
The licensee investigation found a 15-Rem per-hour hot spot adjacent to the work area which went unnoticed by radiological protection technicians in their initial surveys. Although it had alarmed, the increased dose was not picked up on the integrating alarming dosimeter.
This was apparently due to the geometry of the hot spot and the placement of the devic L
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The licensee verified that the individuals had an up-to-date NRC
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Form 4 on file. The inspector independently examined these Form 4s and found them to be satisfactory.
It appears, therefore, that no infraction of 10 CFR 20.101 occurred in that the individuals were eligible for exposure extensions up to 3000 mr per calendar quarter.
Additionally, the licensee found that the other individual's integrating alarming dosimeter had registered no dose received.
It was found that the worker had worn the device under his wet suit. An
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operational check found the device to work accurately under normal conditions.
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The licensee experimented with the device and found that it would not function properly in a high humidity environment. The other device, which did alarm, was found not to be affected by humidity.
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licensee performed testing of 10 additional units and found 8 of them
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The licensee has made the vendor aware of the problem and has made its findings available to the industry through its nuclear network, b.
On two occasions during the inspection period, thi. inspector scanned
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the protected area boundary from the licensee's camera monitors.
The inspector found the licensee to have employed appropriate i
compensatory measures when cameras were rendered inoperable.
7.
Onsite Followup of Events (93702)
a.
On April 21, 1990, while attempting to lower the head on the reactor vessel, the polar crane appeared to slip and inadvertently lower the head such that it impacted with the guide pins installed in the vessel flange.
Upon realizing the interference, the crane operator immediately raised the head and transported it, without incident, to its designated lay-down area.
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Both guide pins were damaged but were subsequently repaired. The vessel head received a gouge from the impact, but it was outside the pressure boundary sealing area. Also, one of the control rod drive j
mechanism (CRDM) gripper fingers received impact.
Licensee management interviewed all personnel involved in the event.
From personnel statements made, the licensee initially focused its investigation on a mechanical problem with the cranes braking mechanism.
The insoector investigated and found that, prior to being placed in service, the crane had undergone appropriate inspections and tests.
The inspector reviewed certified records of the following procedures and encountered no anomalie..
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Procedure EateCompleted
l MM-RI-HE-0550--Polar Crane Annual Inspection 02/2E/90
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MM-RI-HE-0550--Monthly Inspection of Polar Crane 03/09/90-HM-RI-HE-0550--Monthly Inspection of Polar Crane 04/17/90 Additionally, the inspector reviewed records of ali rnaintenance which had been performed on the crane during the current refueling outage and verified that appropriate postmaintenance testing had been performed. The documentation included:
Work Instruction Otte Completed MWO 883115 Replace Polar Crane Feed Cables 04/03/90 and Control Pendants MWO 874145 Repair and Calibration of Polar 03/05/90 Crane Circuit Breaker J
MWO 907520 Adjustment of Speed Controller 02/25/90 MWO 900936 Inspection / Repair of Breaker 03/SC/90 Dash Pots MWO 900941 Repair of Main Hoist Electrical 04/05/90 Limit Switch
MWO 901127 Replace Trolley Pulley Bracket 04/05/90 Chain i
MWO 871918 Repair Defective Section of 04/09/90 Feed Rail MWO 901899 Replace Lugs on Aux Hoist 04/19/90 Resistance Bank
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The licensee's internal investigation likewise uncovered no l
anomalies.
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From April 24-26, 1990, the licensee reperformed inspection and heavy i
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load testing of the crane per Procedure MM-RI-HE-0550.
No anomalies developed.
The licensee also investigated positions taken by personnel in
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installing the head.
It was discovered that, from their vantage points, the exact position of the head could not be determined. The procedure for installation instructa the crane operator to lower the head to approximately 6 inches above the guide pins as directed by the signalman. The signalman, however, is stationed 17 feet above-l l
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i the guide pins at approximately 15 cegrees from the vertical
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resulting in a position from which it is very difficult to estimate depth.
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The licensee straightened the damaged guide pins, performed
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nondestructive testing on the vessel flange in the affected areas,
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and removed the surface discontinuity from the head flange.
Additionally, combustion engineering personnel verified parallelism existed between the flange mating surfaces, and that-the damage to the control rod drive mechanism gripper fingers was insignificant,
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The gripper fingers were also tested to ensure operability.
After recovering from the damages and performing extensive crane
inspection and testing with no negative findings, the licensee concluded the most appropriate explanation for the occurrence was personnel error in estimating distance due to their vantage points.
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The licensee's position is that the crane did not slip and the l
operator simply lowered the head too low causing the interference with the guide pins.
As corrective action, the licensee changed the installation procedure such that a signalman is sent below the head well before contact with the guide pins can be made.
On April 27, 1990, the licensee load tested the crane with the head in the lay-down area.
The test indicated satisfactory crane l
performance.
Immediately after test evaluation, the licensee
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installed the reactor vessel head without incident, b.
On March 23 and April 13, 1990, the licensee experienced a small fire in containment.
In both cases, an individual was welding on the upper level of the containment and sparks fell through the deck grating onto a plastic bag three levels below.
The sparks caused the
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l bags of trash to smolder.
In both cases, the licensee requested
assistance from the Blair, Nebraska, fire department, as required by procedures; however, an individual in the area of the bags immediately extinguished-the fire; therefore, no assistance from the fire department was required.
The licensee had a firewatch stationed near tne site of the weldir.g activities. The licensee stated that, prior to initiation of welding activities, the firewatch inspected the area for combustibles.
However, it did not appear that the individual inspected the areas directly below the site of the welding activities on all three levels.
The inspector reviewed Procedure S0-0-38, " Fire Watch Duties and Turnover Procedures," to verify that appropriate instructions had been provided.
Procedure S0-0-38 stated that the firewatch should check access to areas above, below, and adjacent to affected areas and inspect for combustible materials.
It appeared that the procedure was adequate, as written.
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The licensee stated that a briefing would be provided to each firewatch prior to assumption of his/her duties to ensure that the areas directly below the site of the welding activities is checked for combustibles, c.
On March.12, 1990, the licensee overflowed the spent fuel pool (SFP)
while filling the refueling cavity in containment.
The SFP and cavity are connected by the fuel transfer tube and the containment
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was isolated. As the cavity was being filled, the pressure in containment increased due to the water displacing the air volume, causing a " manometer effect" that resulted in the SFP level being higher than the cavity water level. The licensee had Stauuned an individual in containment, but not in the SFP area, to observe the cavity level increase.
The licensee was filling the cavity in accordance with Procedure 01-FH-2, " Transferring Refueling Water From SIRWT to Refueling Pools." The procedure required that the containment purge be secured, containment isolation be established, and an individual
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be stationed in containment to observe the level increase in the refueling cavity.
The procedure did not require that an individual be stationed at the SFP to observe the level increase.
The nuclear safety review group (NSRG) performed an indepth and comprehensive review to determine the root causes of this event.
The review concluded that the following items contributed to this l
problem:
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Procedure OI-FH-2 was weak and should be revised to require an individual to be stationed at the SFP while filling the cavity, containment pressure be monitored regularly during filling, and containment purge not be secured so that an air-tight containment is established.
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The SFP high-level alarm failed to actuate for unknown reasons.
- Personnel working in the SFP area noticed a level increase above normal but did not notify the control room until the SFP
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overflowed.
- Personnel working in containment and using air-fed hoods did not secure the air supply to the hoods when departing containment.
This contributed to the pressure increase in containment.
The licensee was actively pursuing the implementation of the recommendations made by the NSRG.
d.
On April 18, 1990, the licensee experienced an inadvertent start of EDG 1.
This was the second inadvertent start signal received by an
EDG during this refueling outage. While performing postoverhaul testing of EDG 1, the EDG started to idle speed when the mode selector switch was positioned to " Emergency Standby" from "Off Auto." The EDG started due to an auto-start signal being present
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-16-g which was caused by concurrent trip checks that were being performed on the 345kV -.offsite power. source. This is not a safety-relat.d start signal for which credit is taken in the updated safety analysis report.. It is a e signed anticipatory start which brings the EDG to an idle speed of 500 rpm in anticipation of further electrical system degradation.- This event will be evaluated by the NRC in the closeout of Licensee Event Report 90-12.
8.
Exit Interview The inspectors met with Mr. W. G. Gates, Division Manager, Nuclear Operations and other members of the licensee staff on May 14, 1990.
The meeting attendees are listed in paragraph 1 of this inspection report. At this meeting, the inspectors summarized the scope of the inspection and the findings.
Subsequent to the exit meeting, division management
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confirmed the commitment identified in the cover letter to this inspection i
report.
The licensec did not identify as proprietary any of the material provided to, or reviewed by, the inspectors during this inspection.
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