ML20196F127
| ML20196F127 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 12/01/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20196F105 | List: |
| References | |
| 50-416-98-13, NUDOCS 9812040206 | |
| Download: ML20196F127 (26) | |
See also: IR 05000416/1998013
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50-416.
License No.:
Report No.:
50-416/98-13-
Licensee:
Entergy Operations, Inc.
Facility:
Grand Gulf Nuclear Station
Location:
Waterloo Road
Port Gibson, Mississippi 39150
Dates:
September 20 through October 31,1998
Inspector (s):
Jennifer Dixon-Herrity, Senior Resident inspector
Peter Alter, Resident Inspector
George Replogie, Senior Resident inspector, River Bend
Paula Goldberg, Reactor Inspector
Approved By:
Joseph Tapia, Chief, Project Branch A
Attachment:
Supplemental Information
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9812040206 981201
ADOCK 05000416
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EXECUTIVE SUMMARY
Grand Gulf Nuclear Station
NRC inspection Report 50-416/98-13
This inspection included aspects of licensee operations, maintenance, engineering, and plant
support. The report covers a 6-week period of resident inspection.
Operations
The control room staff continued to exhibit effective communications, a high level of
operator knowledge, and very good oversight. Scheduled work in the switchyard was
well planned and controlled, appropriately addressing the risk associated with the task
(Section 01.3).
With two exceptions, plant equipment was maintained in good material condition and
housekeeping was found to be good. The inspectors identified that fasteners and
temporary restraining cables required as a corrective action for a previously identified
deficiency with grating in containment had not been installed following the refueling
outage. This was identified as a violation for the failure to take corrective actions for a
known deficiency. The practice of staging plastic sheeting and similar lighter materials
in a safety-related room was identified as a poor housekeeping practice (Section O2.1).
Maintenance
The seven maintenance and testing activities observed were properly performed
(Section M1).
The combustible gas control system was in good material condition and aligned to
satisfy Technical Specification requirements (Section M2.1).
Enaineerina
Engineering actions taken in the operability determination of the reactor core isolation
cooling discharge to residual heat removal check valve were acceptable; however, the
documentation of the issue did not quantify the leakage through the valve
(Section E1.1).
The engineering evaluations prior to and after the event involving the near drop of a
heavy load over the reactor were inadequate. Engineering personnel did not have a full
understanding of the requirements of NUREG-0612 or Grand Gulf's commitments to
comply with NUREG-0612. The engineering screening for this evaluation was
inadequate and was a missed opportunity to identify Updated Final Safety Analysis
Report (UFSAR) requirements and the need to perform a safety evaluation. This was
identified as an example of failing to follow procedures. Three additional examples of a
violation for failure to follow procedures were identified. The examples included the
failure to perform a safety evaluation for a heavy lift and a safety evaluation applicability
review for the procedure to perform the heavy lift, failure to ensure that adequate special
lift procedures were developed, and failure to coordinate the heavy lift with the control
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room supervision (Section E8.6).
The inspectors concluded that the root cause analysis report conducted for the event
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involving the near loss of a heavy load over the reactor was less than adequate. The
conclusions reached were narrowly focused and did not comply with the definitions
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provided in the corrective action program. The report failed to identify the f ailure of
personnel to follow procedures or the failure of enginee. ring personnel to understand
regulatory requirements that were in place. Both of these failures contributed to the
event and would have to be corrected to prevent recurrence (Section E8.6.5).
Plant Support
With one exception, observed activities involving radiological controls were well
performed. The inspectors identified one poor posting practice where the posting
around a high contamination area did not meet the licensee's documented guidance
(Section R1,1).
Routine reactor coolant chemistry and dose equivalent iodine sampling and analysis
were completed proficiently and in accordance with the procedures (Section R4.1).
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Report Details
Summarv of Plant Status
The plant operated at 100 percent power until October 21,1998, when operators lowered
power to 48 percent as a result of the trip of circulating Pump A. After conducting repairs, the
plant was returned to 100 percent power on October 22,1998, and operated at that level the
remainder of the inspection period.
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l.' Operations
01
Conduct of Operations
01.1 General Comments (71707)
The inspectors performed control room observations to ascertain operator knowledge
and performance. Operators exhibited good three-way communications and peer
review. Operations shift turnovers and briefings were thorough and conducted
professionally. Operators were knowledgeable of the status of equipment, and
applicable Technical Specification limiting conditions for operations were appropriately
documented.
01.2 Work in the Switchyard
a.
Inspection Scope (71707)
The inspectors reviewed the licensee's planned work in the switchyard and toured the
switchyard to determine the effect the work had on offsite power sources.
b.
Observations and Findings
The switchyard work planned consisted of the removal of two 500 Kva breakers the
licensee had installed for a future offsite power line and to support Unit 2 and the
replacement of the breakers with bus work. The licensee decided to remove the
breakers because of the high cost of maintenance and abandonment of the plans to add
a third 500 Kva offsite power source or to complete Unit 2. The plans the licensee
developed for removal of the breakers were detailed and thorough. The work
coordinator provided daily status on the project to the control room and at the morning
meeting. The licensee had areas in the switchyard roped off to control traffic and lower
the risk of the work being performed. The equipment in the switchyard was in good
material condition.
During the removal of the second breaker, the inspectors noted that work was
scheduled to be conducted on the Division 3 diesel generator's foundation. The task
consisted of removing tack welds from foundation floor plates to allow access under the
diesel generator. During the turnover in the control room and discussions at the
morning maintenance planning meeting, supervisory personnel stressed that fire
protection personnel were to be involved in the preparation and conduct of the work in
the vicinity of the diesel due to the grinding work that was going to occur. The
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inspectors questioned whether the licensee had considered the level of risk with
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personnel working in the vicinity of the diesel and personnel working in the switchyard.
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The assistant to the operations superintendent explained that this had been specifically
considered during the plant safety review committee meeting where the 10 CFR 50.59 screening for the task was reviewed. The work in the switchyard could occur as
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long as the diesels were functional. The inspectors considered the task, toured the
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diesels where the work was to occur, and determined that the increase in risk would not
be great due to the limited controls and equipment that could be affected in the area
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where the work was occurring.
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The inspectors reviewed the 10 CFR 50.59 screening and the standing order developed
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to support the planned work. Both of these documents were accurate and appropriately
addressed the tasks. Control room personnel had the authority to stop work in the
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switchyard if necessary. This option was taken on October 7 and 28,1998, due to the
concern identified with the reactor core isolation cooling check valve and approaching
bad weather on the first date and due to perturbations on the grid on the second. No
risk significant work was planned or performed during removal of the breakers.
O1.3 Conclusions for Conduct of Operations
The control room staff continued to exhibit effective communications, a high level of
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operator knowledge, and very good oversight. Scheduled work in the switchyard was
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well planned and controlled, appropriately addressing the risk associated with the task.
O2
Operational Status of Facilities and Equipment
O2.1
Plant Tours
a.
Inspection Scope (71707)
The inspectors routinely toured the accessible portions of the plant containing safety
and risk significant structures, systems, and components.
b.
Observations and Findinas
The inspectors found that plant equipment was maintained in good material condition
and that plant housekeeping was good with two exceptions On October 14,1998, while
touring the containment, the inspectors noted that six grat'ngs on the * boat dock" on the
114-foot 6-inch elevation were not fastened to the support structure. The inspectors
recalled that this had been a concern prior to the refueling outage and discussed the
concern with the shift superintendent. The shif t superintendent had personnel check on
the concern and verified that no fasteners had been installed in the gratings the
inspectors questioned. The superintendent documented the concern in Condition
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Report 1998-0014-04. The immediate corrective actions taken included fastening down
the grating, inspecting the grating in the containment to verify that there was no other
loose grating, and requesting that engineering evaluate the impact of the grating on
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equipment. Licensee personnel identified three additional discrepancies during the
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inspection in containment, but all other gratings were found to be fastened in place by at
least one fastener.
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Tl e inspectors reviewed the history of the concern. The licensee identified in Condition
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Report 1998-0014-01 on January 14,1998, that not all grating was fastened down.
During the engineering evaluation that occurred as a result of this deficiency, the
licensee identified that grating Sections 77,78,86,87,88,89,90,91,92,93, and 94, all
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sections of gratings on the boat dock, needed additional restraints. The existing grating
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clips capacity was not sufficient to hold the grating in place during a suppression pool
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swell event, opening up the possibility that equipment in the area could be damaged if
the gratings came loose and became missiles. Until a permanent change could be
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made, the licensee installed temporary cables to fasten the gratings to the supporting
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structure below.
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The inspectors found grating Sections 77,78,91,92,93, and 94 unsecured. During the
licensee's inspection, the licensee determined that none of the temporary cables had
been installed following the refueling outage that ended May 21,1998. The engineering
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evaluation completed on January 22,1998, found that there was no safety-related
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equipment in the vicinity that would be damaged by the grating. However, the
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inspectors noted that the full toroid suppression pool suction strainer had been installed
during the recent refueling outage and that the strainer ran under the boat dock, so -
there was now potential for safety-related equipment to be damaged. The licensee
reported this concern to the agency via a 10 CFR 50.72 report and planned to submit a
licensee event report (LER). The inspectors toured the containment and verified the
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temporary cables were installed to secure the gratings in place. The inspectors
identified the failure of the licensee to reinstall the temporary cable restraints previously
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installed to address an identified deficiency with the grating as a violation of
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10 CFR Part 50, Appendix B, Criterion XVI (Violation 50-416/9813-01). The inspectors
found that the immediate corrective actions taken to address the deficiency and the
corrective actions planned were thorough and should prevent recurrence.
On October 23,1998, while touring the auxiliary building, the inspectors noted that
personnel who had been cleaning the alternate decay heat removal system heat
exchangers had left equipment staged in the residual heat removal Train C room. In
addition to heavy buckets of tools and a mop bucket, personnel had left a large sheet of
plastic, rubber boots, and an empty plastic bucket. The inspectors were concemed that
the lighter plastic items would have the potential to block the drains during a flooding
situation. The inspectors noted that this concern was previously discussed as a poor
housekeeping practice in NRC Inspection Report 50-416/98-09. The inspectors
discussed the concern with the plant supervisor and the supervisor had the items
removed.
c.
Conclusions
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With two exceptions, plant equipment was maintained in good material condition and
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housekeeping was found to be good. The inspectors identified that fasteners and
temporary restraining cables required as a corrective action for a previously identified
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deficiency with grating in containment had not been installed following the refueling
outage. This was identified as a violation for the failure to take corrective actions for a
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' known deficiency. The practice of storing or staging plastic sheeting or similar lighter
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materials in a safety-related room was identified as a poor housekeeping practice.
11. Maintenance
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M1
Conduct of Maintenance
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M1.1 General Maintenance Comments
a.
Insoection Scope (62707)
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The inspectors observed portions of maintenance activities, as specified by the following
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work orders:
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209951
VOTES testing of high pressure core spray outboard test return to
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the condensate storage tank, Valve 1E22-F010
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214721
Troubleshooting of reactor core isolation cooling discharge to
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residual heat removal check Valve 1E51-F065
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214820
Troubleshooting of control rod drive water flow oscillations
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215253
Standby liquid control Train A postmaintenance test
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b.
Observations and Findinos
The inspectors found the performance of this work to be satisfactory. All work observed
was conducted in accordance with the instructions and procedures provided in the work
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packages. The technicians performing the tasks were knowledgeable of the equipment
and used good work practices.
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M1.2 General Surveillance Comments
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a.
Insoection Scope (61726)
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The inspectors observed portions of the following surveillances:
06-IC-1E61-O-1004, Containment and Drywell Hydrogen Analyzer Calibration
06-OP-SP64-W-0001, Fire Pump Weekly Operability Test
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06-OP-1E61-O-0003, Drywell Purge System Operability
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b.
Observations and Findinas
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The inspectors noted that the test procedures provided clear guidance and properly
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implemented Technical Specification requirements. Measuring and test equipment was
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verified to be within its current calibration cycle. As necessary, instrumentation was
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removed from service, applicable limiting conditions for operation were entered, and the
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instrumentation was properly returned to service. The operators and technicians were
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very knowledgeable and qualified. As-found test data was within the tolerance
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established for the equipment. Personnelinvolved demonstrated good communications
and attention to detail.
M1.3 Conclusions on Conduct of Maintenance
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The seven maintenance and testing activities observed were properly performed.
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M2
Maintenance and Material Condition of Facilities and Equipment
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M2.1 Enaineered Safety Feature System Walkdown
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a.
Inspection Scope (71707)
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The inspectors performed detailed system walkdowns of the accessible portions of
Combustible Gas Control System. The inspectors verified proper valve, controi board,
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and electrical alignment in accordance with Procedure 04-1-01-E61-1, " Combustible
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Gas Control System," Revision 30, and Piping and Instrument Diagram M-1091,
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" Combustible Gas Control Systems Unit 1," Revision 27.
b.
Observations and Findinas
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The inspectors found that the postaccident hydrogen analyzers, hydrogen recombiners,
containment purge, and drywell vacuum relief and purge subsystems of the combustible
gas control system were properly aligned to assure system operability in accordance
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with the applicable procedure and drawing. The alignment satisfied Technical
Specifications and UFSAR requirements. Major components were properly labeled,
lubricated, and free of identifiable leakage.
c.
Conclusions
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The combustible gas control system was in good material condition and aligned to
satisfy Technical Specification requirements.
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lit. Enaineerina
E1
Conduct of Engineering
E1.1
Enaineerina Evaluation of the Reactor Core isolation Coolina Check Valve
a.
Inspection Scoce (37551)
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The inspectors observed design and system engineering support of the test to verify
reactor core isolation cooling discharge to residual heat removal check
Valve 1E51-F065 closure and to determine actual valve leakage.
b.
Observations and Findinas
On October 6,1998, during performance of full stroke testing of reactor core isolation
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cooling injection shutoff Valve 1E51-Fn13, control room operators observed unusual
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flow and pressure indications which lead them to question whether there was leakage
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through Valve 1E51-F065. The operators declared the system inoperable and entered
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Technical Specification 3.4.6 for increased leakage across the check valve. Plans to
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address the concern were developed promptly during a meeting held early in the
morning. Engineering personnel developed a one time test instruction to verify actual
leakage through Valve 1E51-F065.
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The test performed and the subsequent operability recommendation enabled the
operations shift superintendent to determine that Valve 1E51-F065 complied with
Technical Specification 3.4.6 for reactor coolant system pressure isolation valve -
leakage. The superintendent declared the valve operable and returned the reactor core
isolation cooling system to service.
The inspectors reviewed the test results prepared by engineering personnel. The first
portion of the test measured the pressure that had developed between
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Valves 1E51-F065 and 1E51-F013 in approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> since operators closed
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Valve 1E511-F013. During that period,1100 psig had developed, indicating that
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Valve 1E51 F065 did leak over time. The second part of the test verified that
Valve 1E51-F065 closed by opening Valve 1E51-F013 and other valves in the lineup
and verifying a maximum pressure was not exceeded. The pressure in this case was
O psig, showing that the valve was in the closed position. Last, engineers measured the
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pressure between Valves 1E51-F065 and 1E51-F013 after closing the latter to see if
there was an increase in pressure. Pressure was recorded for a 10-minute interval and
there was a O psig increase. The engineers used this information to determine that
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there was no leakage through the valve and that the valve was within the Technical
Specification one gpm limit.
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The inspectors questioned whether the leakage indicated in the first part of the test,
where 1100 psig built up over an approximate 18-hour period, had been quantified. The
engineering supervisor explained that the last test performed was similar to the
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Technical Specification required local leak rate test that was conducted on the valve
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during outages; however, pressure was used as an indicator rather than actual leakage.
The supervisor also explained that Valve 1E51-065 had not had any identified leakage
during the localleak rate tests performed since startup. The system engineer explained
that no calculations had been performed to quantify the leakage over the 18-hour
period. However, they had set up a computer program to check what leakage into the
system would have to occur to allow a buildup of 1100 psig, and that amount, with the
system fully vented, was one pint. With trapped air, the amount of leakage would be
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greater; however, the 10-minute test indicated that there was little leakage when the
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pressure differential was maintained.
c.
Conclusions
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Engineering actions taken in the operability determination of the reactor core isolation
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cooling discharge to residual heat removal check valve were acceptable; however, the
documentation of the issue did not quantify the leakage through the valve.
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E8
Miscellaneous Engineering lasues (92903)
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E8.1
(Open) insoection Followuo item 50-416/9603-01: Review long-term justification for
- methodology and assumed valve factors. The inspectors noted that the licensee
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performed differential pressure testing for two additional valves from the 150 lb. Powell
Gate Valve GA1 group and two additional valves from the 600/900 lb. Powell Gate Valve
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group during Refueling Outage 9. The inspectors reviewed the test data. The test data
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from the 150 lb. GA1 group indicated valve factors of 0.522 and 0.422 for the two 4-inch
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valves tested. For the 600/900 lb. Powell Gate Valve group tests, the licensee
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determined that the valve factors were 0.455 for the 12-inch valve and 0.471 for the
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18-inch valve. The licensee's preliminary review of the test data indicated that the
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bounding valve factors of 0.62 for the 150 lb. valves and of 0.50 for the 600/900 lb.
valves were acceptable. The licensee stated that the differential pressure test data was
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being evaluated and would be documented in Engineering Report 0048-98. The
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licensee had not completed their analysis of the test data using uncertainties. The
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inspectors concluded that the licensee was making progress in determining valve
factors. This item will remain open pending NRC review of the final analysis which will
be documented in Engineering Report 0048-98.
E8.2 (Closed) Inspection Followuo item 50-416/9611-01: Review of the UFSAR description
of safety relief valve logic. The inspectors reviewed Engineering Response 97/0313,
Revision 0, which installed a capacitor in the feedback circuit of the comparator which
provided the trip function of the trip unit. The capacitor functioned to provide the
comparator feedback circuit with a time delay to prevent spurious signals from sealing in
the trip unit. The licensee found that the capacitor had no affect on the trip unit's ability
to react and trip due to a true pressure signal. The modification involved the installation
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of _a safety-related capacitor on each of the safety relief valve low-low set trip units. The
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inspectors determined that the licensee's corrective actions were adequate to avoid
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additional spurious openings of the safety relief valves.
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The inspectors reviewed the GE Safety Analysis Report, which identified the number of
safety relief valves that could open at the same time. The Safety Analysis Report
discussed two adjacent valves opening as one of the cases. The report stated that the
probability of the combination of two adjacent valves opening would be very low, since
the valves that have the same setpoints are uniformly distributed around the
suppression pool. It further stated that the containment structural design requirements
of two adjacent valves opening were satisfied under the asymmetric condition, and
subsequent analysis was not necessary for the multitude of other more probable
asymmetric load cases. The inspectors found that the Safety Analysis Report also
discussed two symmetric cases for containment loads. The cases were 8 automatic
depressurization system valves opening and all 20 of the valves opening. The licensee
stated that the 6 valves that opened were symmetrically located around the suppression
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pool and were bounded by the analysis (of all 20 valves opening or the 8 automatic
depressurization valves opening).
In addition, the licensee stated that the Safety Analysis Report was based on
reestablishing pressure to normal operating pressure for the analysis. If there was an
initiallift of all 20 of the safety relief valves followed by an inadvertent lift of 6 valves, the
pressure during the second lif t would be significantly lower; therefore, the forces would
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be lower also. The inspectors reviewed the UFSAR drawing of the layout of the 20
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safety relief valves and found that each safety relief valve had its own tailpiece, which
prevented the valves from discharging into a common header which would increase
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loading. The inspectors concluded that the case of the six safety relief valves
inadvertently opening was bounded by existing analysis.
E8.3
(Closed) U.nresolved item 50-416/9705-02: Lack of leak tests for nonsafety-related to
safety-reated system interface valves. The inspectors reviewed Program
Plan GGNS-M-189.1," Pump and Valve Inservice Testing Program," Revision 8. The
inspectors noted that the 13 nonsafety-related boundary valves were in the inservice
testing program. A telephone conference was held with the licensee, the inspectors,
and the NRC Program Office on September 21,1998, to discuss this unresolved item.
The position of the NRC Program Office was that, since the licensee determined that a
total system leakage limit, rather than a valve specific leakage limit, was appropriate,
ASME Section IX, Category A, testing did not apply and the licensee was appropriately
testing the boundary valves.
E8.4
(Closed) Violation 50-416/9705-06: Test control deficiencies. The inspectors reviewed
the licensee's June 30,1997, response to the violation. For the first example of the
violation, the licensee stated that they believed that their surveillance procedures were in
compliance with 10 CFR Part 50, Appendix B, Criterion XI. In addition, the licensee
stated that the incorporation of the limits was viewed as an appropriate enhancement.
The inspectors reviewed Condition Report 1997-0623, dated June 23,1997. The
condition report addressed whether there was a need to revise the standby service
water (SSW) and the high pressure core spray surveillance procedures to verify that the
pump capabilities to remove heat loads were being met. The licensee concluded that,
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since there was no explicit surveiliance requirement in the Technical Specifications to
verify the heat removal capabilities of equipment supported by the SSW and high
pressure core spray systems, the surveillance procedures would not be revised. In
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addition, the licensee stated that an explicit SSW and high pressure core spray service
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water loop analytical flow rate limit was not clearly specified in the accident analyses for
the assumed heat removal capabilities of the interfacing equipment. Furthermore, the
licensee concluded that the analytical flow rate limit alone would not assure the plant
was operated within the assumptions of the accident analyses, since heat transfer rates
were based on the degree of fouling in the heat exchangers as well as the pump flow
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rates. Based on these reasons, the licensee decided not to revise the surveillance
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procedures. The inspectors reviewed Condition Report 1997-0266, dated
May 15,1997. The inspectors noted that the licensee committed to revising the
hydraulic model calculations to incorporate the 10 percent flow degradation margin
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allowed by ASME Section XI. This would allow the lower limit flow values from the
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inservice test program to match the hydraulic models. The inspectors deterrnined that
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the first exampl-e of the violation was closed.
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For the second example of the violation, the inspectors reviewed Procedures 17-S-06-
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Revision 4, and Technical Change Notice 2; 17-S-06-23, "SSW B Performance,"
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Revision 5, and Technical Change Notice 5; and 17-S-06-24, "SSW C Performance,"
Revision 2. The inspectors determined that the procedures were revised to include
revised data sheets and to add notes and precautions to clarify desired and minimum
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flow values. The inspectors noted that the acceptance limits for design values for
required minimum heat transfer rates from Engineering Standard GGNS-MS-39.0 were
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included on the data sheets. The inspectors concluded that acceptance criteria had
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been incorporated into the surveillance procedures. The inspectors determined that the
second example of the violation was closed.
The inspectors reviewed Calculation MC-Q1P41-97036," Determination of Fuel Pool
Cooling and Cleanup Heat Exchanger Capability," Revision 0, and noted that the
calculation superseded previous calculations. The purpose of the calculation was to
determine the thermal performance capability of the fuel pool cooling and cleanup heat
exchangers under various operating conditions using appropriate fouling levels for the
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heat exchangers. The inspectors reviewed Program Plan GGNS-M-189.1,". Pump and
Valve Inservice Testing Program," Revision 8, and found that the fuel pool cooling and
cleanup pumps and valves were in the inservice testing program. The inspectors
reviewed Calculation MC-Q1P41-97035,"SSW Heat Exchanger Thermal Performance
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Instrument Uncertainty," Revision 1, which was prepared to validate the current
instrument uncertainty evaluation methodology. The inspectors reviewed
Standard GGNS-MS-39.0, " Mechanical Standard for Thermal Performance Testing of
Safety-Related SSW Heat Exchangers." The inspectors determined that the standard
was revised to incorporate the latest plant practices concerning thermal performance
instrumentation requirements and error measurement, evaluation, application, and the
most conservative design requirements for the fuel pool cooling heat exchangers. The
inspectors noted that the maximum heat duty design value for the heat exchangers was
revised. The inspectors concluded that the licensee had completed all of the corrective
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actions committed to in their June 30,1997, response to the violation. The inspectors
determined that the third example of the violation was closed.
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In the licensee's June 30,1997, response letter to the fourth example of the violation,
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the licensee committed to the same corrective actions as the third example to the
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violation. Therefore, the inspectors concluded that the fourth example of the violation
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was closed.
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E8.5 (Closed) Unresolved item 50-416/9705-07: Further review of licensee basis of current
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flood calculation. The inspectors reviewed Calculation CC-01Y23-91015," Probable
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Maximum Precipitation Site Drainage - Water Level and Duration in Area East and West
of Unit 1 Power Block for a 6 Hour Probable Maximum Precipitation Storm." The
purpose of the calculation was to determine the water level versus time history for areas
)
surrounding the Unit 1 power block, including the SSW buildings, for a 6-hour storm
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event. The inspectors found that the maximum water levels during peak flows for the
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SSW pump houses were 132.54-feet for the west house and 132.84-feet for the east
house. The inspectors noted that maximum water levels during flooding were lower
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than the 133-foot floor level of the pump houses.
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The inspectors reviewed Supplemental Safety Evaluation Report 6. The NRC reviewed
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the licensee's request to delete Technical Specification 3/4.7.10 and add a requirement
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for an embankment stability verification program in Technical Specification 6.0. The
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change would have relaxed the limiting condition for operation for the specification that
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ensured that Culvert 1 on the plant site would not be blocked. In addition, while the
present specification required action to verify slope stability and clean the culvert, with
an allowed blockage of 15 percent of its own sectional area, the proposed specification
would not require this until the blockage was 45 percent. While the NRC staff
concluded that the change from a specification to a program was not acceptable, the
staff also concluded that the percent blockage for Culvert 1 could be changed from 15 to
45 percent. The NRC staff performed a preliminary analysis and determined that, with
the culvert 100 percent blocked, the flood elevation would reach 134 feet or 1 foot above
the pump house floor level. Due to the 134-foot flood level with the culvert 100 percent
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blocked, the NRC sta'f determined that the Technical Specification remained in effect
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with a maximum culvert blockage of 45 percent. The inspectors reviewed Calculation C-
A-634.0," Probable Maximum Precipitation Site Drainage - Culvert #1 and Subarea
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Hydrographs to Assess the Blockage of Culvert # 1," Revision 1. The inspectors found
that with 45 percent blockage of Culvert 1, the water level would be 132.8-feet, which
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was lower than the floor elevation of the pump house.
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The inspectors reviewed Engineering Request 97/0460, dated August 28,1997, which
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was a design modification that installed 71/2-inch high toe plates completely around the
SSW pumps. The modification was done to ensure that leakage from the pumps,
valves, or roof hatches would not propagate toward the floor mounted e!ectrical
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equipment. In addition, the inspectors reviewed Engineering Request 97/0244, dated
March 18,1997. This engineering request described the problem with the missing
pump seals. The inspectors noted that the engineering request was dispositioned to
rework the seals to assure that the pump bases were sealed. The inspectors walked
down the SSW pump rooms and found that the modification was fully implemented and
the pump bases were sealed. The inspectors observed that, although the pump bases
were resealed, they were no longer necessary since the pumps were completely
enclosed by the toe plates installed by the modification.
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Design Drawing C-1736B, " Units 1 & 2 SSW Cooling Tower Basin Misc. & Embedded
{
Steel Sections & Details," Revision 8, specified that a continuous bead of silicone
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sealant be applied around the bases of the SSW pumps. During the 1997 inspection,
the inspectors discovered that the seal was missing from the SSW pumps. The
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licensee did not know when the seals were deleted. The inspectors concluded that the
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missing seals were not safety significant since the flooding calculations indicated the
.
water would never reach the SSW pump room floors. This failure constitutes a violation
of minor significance and is not subject to formal enforcement action.
E8.6 (Closed) Insoection Followup Item 50-416/9805-01: Further review of licensee's
3
investigation into the loss of control of heavy lift. In conducting this review, the
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inspectors interviewed personnel involved in the event and the investigation and
reviewed the following documents:
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UFSAR Section 9.1.4.2.2.5, " Compliance with NUREG-0612," and Appendix 9D,
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"GGNS Compliance with NUREG-0612, ' Control of Heavy Loads at Nuclear
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Power Plants'"
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NUREG-0612," Control of Heavy Loads at Nuclear Power Plants"
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ANSI N14.6-1978, "American National Standard for Special Lifting Devices for
Shipping Containers Weighing 10,000 pounds (4500 kg) or more for Nuclear
Materials"
Procedure 07-S-05-300," Control and Use of Cranes and Hoists," Revision 104
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Procedure 07-S-05-310," Operation of Containment Polar Crane," Revision 100
=
Procedure 01 S-06-2," Conduct of Operations," Revision 104
Procedure STD-FP-1996 7674,"BWR Shroud Inspection Tooting Installation and
Removal," Revision 2
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Engineering Request 98/0209-000. " Plant Staff requested Design Engineenng to
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evaluate the rigging fixtures for the Theta Drive and the R-Z Drive related to the
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Shroud Inspection Program"
Root Cause Analysis Report " Vendor Shroud Inspection Tool Theta Drive and
Ring Partial Release from Tool Strongback," dated August 11,1998
Entergy Operations, Inc. Grand Gulf Nuclear Station Stand-Alone
Contract NGS00456
!
With one exception, the description of the event in NRC Inspection Report 50-416/98-05
was accurate. Upon conducting the investigation, the licensee found that the vendor
,
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provided incorrect weights for the tool ring and the strong back assembly or special
lifting rig. The ring weighed 1130 lbs in lieu of 850 lbs. and the lifting rig weighed
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360 lbs. in lieu of 640 lbs.
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E8.6.1 Procurement of Vendor Services
The licensee's root cause analysis report identified that the theta drive and ring and the
R-Z drive were used twice at Grand Gulf Nuclear Station, during vendor shroud
inspection work that took place during Refueling Outages 7 and 9. This service was
procured through a contractor on the licensee's quality programs list of contractors with
an Entergy approved Appendix B quality assurance program. The only procedures
specifically required to be reviewed in the contract were the nondestructive examination
procedures. The licensee identified that the failure to require that the vendor support
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procedures be submitted for review and approval in accordance with the work control
procedures was a potential contributing cause to the event.
The licensee completed the installation and removal during both refueling outages
through repetitive tasks, which were allowed to be used through the work control
procedure due to the use of previously approved procedures. In this case, the
procedures were approved through the vendor's quality assurance program. When the
equipment was used during Refueling Outage 7, the total weight of the lif ting device and
the ring was less than 1140 lbs. The UFSAR required that administrative controls be
put in place for lifts that weighed less than 1140 lbs. The licensee met these
requirements in Refueling Outage 7 by administratively limiting the weight and height,
depending on whether secondary containment and standby gas treatment systems were
available.
The equipment was modified after being used during Refueling Outage 7 and at another
site in 1996 as a result of lessons learned. The modifications were completed just prior
to Refueling Outage 9. The modifications resulted in increasing the weight of the theta
drive, ring, and lifting device and the R-Z drive and lifting device to greater than
1140 lbs. (1490 lbs. and 1250 lbs., respectively). UFSAR Appendix 9D, Section 9D.3,
stated that heavy loads (loads greater than 1140 lbs.) that can be handled in
accordance with Section 5.1.1 guidelines of NUREG-0612 are not evaluated for load
drop consequences. Any heavy load not handled in accordance with the Section 5.1.1
guidelines is evaluated to determine that the consequences of it dropping are
acceptable per the criteria of NUREG-0612, Section 5.1.
The inspectors noted that the increase in weight to greater than 1140 lbs. invoked
additional requirements that were not addressed in the procurement contract. However,
the contract was developed and the services procured (February 4,1998) before the
modifications to the equipment were completed (in March). The licensee was not aware
of the increase in weight until receipt of contractor Letter SGRR-ES-98-41, Revision 1,
dated April 3,1998. On approximately April 10,1998, licensee personnel observed that
there had been a weight change in the tool to be used during the shroud inspection.
Letter SGRR-ES-98-41, which documented the weight change and a calculation
performed to determine whether the safety factors of the theta drive and R-Z drive lifting
fixtures met the NUREG-0612 guidelines, was forwarded to design engineering via
Engineering Request 98/0209 for evaluation.
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E8.6.2 Enaineerina Evaluation
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The inspectors reviewed the engineering reply to Engineering Request 98/0209.
Procedure 01-S-17-5, " Engineering Request," Revision 6, Section 6.5.3, states that an
engineering reply provides information obtained from existing reference documents or
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standard engineering practices, or elaborates on or interprets existing information, and
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that the engineering reply cannot be used to control actions in the field.
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In the engineering reply, the engineer determined that the engineer licensing documents
(UFSAR) were not affected and a 10 CFR 50.59 safety evaluation was not required.
The reply directed that the drives be handled such that the load path be by the shortest
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route possible and the height be limited to no more than 6 inches above the 808-foot
10-inch floor or the top of any intervening obstruction that may be mounted or staged on
the refueling floor. The inspectors concluded that the screening was a missed
,
opportunity to identify UFSAR requirements and that the engineer failed to adhere to the
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directions for developing an engineering reply in that the reply provided direction to
control actions in the field.
The engineering reply found that both loads were greater than 1140 lbs. and had to be
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treated as heavy loads at Grand Gulf. The engineering reply listed the vendor's
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acceptance criteria and assumptions in the calculations and the safety factors the
vendor calculated. The inspectors found that the evaluation detailed the requirements
for safety factors (the factor of safety may be 5 for the Theta drive lifting fixture, but
must be a minimum of 10 for the R-Z drive) and a chain fall hoist because of the lack of
redundancy, as described in NUREG-0612, Section 5.1.6, which deals with single
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failure-proof handling systems. The licensee was not required to meet these criteria,
!
per UFSAR Section 9D.2.2, which states that the objective of NUREG-0612 was met
without the need for further action by Grand Gulf regarding Phase 11 (NUREG-0612,
,
Section 5.1.2 through 5.1.6).
NUREG-0612, Section 5.1.1(4), requires that the guidelines of ANSI N14.6-1978,
" Standard for Special Lifting Devices for Shipping Containers Weighing 10,000 pounds
!
(4500 kg) or More for Nuclear Materials," apply to all special lifting devices which carry
heavy loads over defined areas. In the case of the lift of the shroud inspection tooling,
the total lift weighed greater than 1140 lbs., although, the load being lifted by the special
lifting device weighed less than 1140 lbs. In the engineering reply, the theta ring
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assembly was conservatively considered to be a heavy load. The licensee determined
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that the speciallifting rig met ANSI N14.6-1978 requirements and the requirements of
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NUREG-0612 based solely on a review of the safety factors.
ANSI N14.6-1978 calls out five design criteria, in addition to the safety factors. It also
identifies eight different design considerations. Among these are considering the
problems related to the environment in which the device will operate, ensuring that
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positive locking mechanisms are provided for load-carrying components that could
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become disengaged, and providing a method of retrievalin case of unintentional
disengagement for devices used in pools. In addition to these requirements, design
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considerations to minimize decontamination, the coatings to be used, method of
f abrication, inspection, acceptance testing, maintenance, and assurance of continued
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compliance with the standard were addressed. The inspectors determined that these
criteria were not evaluated or even questioned prior to determining that the vendor
supplied rigging fixture was approved for use.
The inspectors discussed this concern with the engineering supervisor responsible for
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the evaluation. The supervisor explained that not all the requirements of ANSI N14.6-
1978Property "ANSI code" (as page type) with input value "ANSI N14.6-</br></br>1978" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. were applicable because the load on the lifting rig was less than 1140 lbs. The
inspectors were concerned that the acceptance criteria selected by the engineer were
not identified in an approved procedure or in the design basis and were not approved for
use. In not providing acceptance criteria to evaluate the speciallifting device, evaluating
it in accordance with ANSI N14.6-1978, or providing compensatory measures to address
the lack of evaluation, the inspectors concluded that the licensee jeopardized the
defense-in-depth developed through use of NUREG-0612. The engineering supervisor
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acknowledged that the evaluation was not at the level normally expected by engineering
management. The failure to follow the instructions in Procedure 01-S-17-5 for the
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screening and development of the response to the engineering request was identifiea as
the first example of a violation of 10 CFR Dart 50, Appendix B, Criterion V
(Violation 50-416/9813-02).
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The licensee's root cause analysis report stated that system engineering reviewed the
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engineering reply, the vendor's procedure for the installation and removal of the tooling,
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and Procedures 07-S-05-300 and 07-S-05-310 on April 17,1998, in order to ensure
understanding of the reply and compliance with procedural requirements. This review
was only documented in the root cause analysis report. Based on the direction provided
in the reply and the three procedures, system engineering determined that respective
requirements were met for lift and installation of the vendor shroud inspection tool. The
inspectors considered this an additional missed opportunity to identify discrepancies
with meeting the regulatory requirements and site procedures.
In a subsequent clarification for the evaluation, design engineering addressed the
question "Was the Theta Drive Lifting Rig evaluated for full compliance with
NUREG-0612 and ANSI N14.6-1978 as a special lifting device?" Engineering found that
the device was not a special lifting device because it was not required to carry 1140 lbs.
Engineering personnel failed to question the absence of acceptance criteria for the
lifting device or the weak point created in the defense-in-depth approach. The vendor
did not submit additional information to demonstrate compliance with the other sections
of ANSI N14.6-1978. Engineering personnel found through discussions held during the
investigation that the lifting rig was designed to meet other applicable provisions of
ANSI N14.6-1978. Engineering personnel never requested this information prior to the
event nor evaluated the information further beyond the discussions held. At the close of
the clarification, engineering personnel concluded that the lifting rig was designed and
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tested in a manner consistent with the Grand Gulf commitments to NUREG-0612 and
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ANSI N14.6-1978. The inspectors concluded that the evaluations prior to and after the
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event were inadequate and that engineering personnel did not have a full understanding
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of the requirements of NUREG-0612 or Grand Gulf's commitments to comply with
4
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E8.6.3 Procedures
The areas required to be satisfied by NUREG-0612 included: (1) safe load path,
(2) procedures for load handling operations for heavy loads, (3) training and qualification
of crane operators, (4) special lifting rigs, (5) lif ting devices that are not specially
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designed, (6) inspection, testing and maintenance guidance for the cranes, and
(7) design guidance fcr the crane. Procedure 07-S-05-300 specifically addressed a
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number of these areas, including the training of operators, inspections and pre-
operation checks for the cranes, and general directions for lifting loads. The procedure
referred to Procedure 07-S-05-310 for overall guidance, but required that loads in
excess of 1140 lbs. have special lift procedures and be handled in accordance with
Section 5.1.1 of NUREG-0612.
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Procedure 07-S-05-310 required that nonstandard heavy loads be directed by the refuel
floor manager or his designee who will have overall responsibility for safe handling of
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the load and that all Safety Class 1 loads have a speciallift procedure. The procedure
)
referred to a list of standard heavy loads in Attachment 1. Attachment I contained a
Zonal Load Restriction Chart which required that loads greater than 1140 lbs. not be
carried over fuelin the reactor cavity without a safety evaluation. In addition, this
procedure defined the different safety classes which Grand Gulf has been approved to
]
use in place of safe load paths. The procedure stated that the procedural actions were
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included in the maintenance instructions for each heavy lift, based on the safety class
assignments for the heavy load.
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The inspectors determined that the licensee met the first, third, sixth, and seventh areas
addressed in NUREG-0612, Section 5.1.1, through the two procedures addressed
above. The requirement to have a special lift procedure should have met the second
area. In this case, the procedure was prepared by the vendor and the licensee did not
require that the speciallift procedure be reviewed. Procedure STD-FP-1996 7674 did
not limit the time and the height the load was carried over the area of concern,
contained no inspection requirements or acceptance criteria to be met prior to
movement of the load, and did not address special precautions as required by the
UFSAR and .NUREG-0612. The procedure was a generic procedure developed by the
vendor for use of the vendor's equipment and not reviewed or approved by the licensee
to verify that it met the licensee's regulatory requirements for heavy lifts. The failure to
ensure that a procedure appropriate to the circumstances was used during the heavy lift
was identified as a second example of a failure to meet 10 CFR Part 50, Appendix B,
Criterion V (Violation 50-416/9813-02).
The inspectors questioned whether a safety evaluation had been completed in
accordance with the requirement in Procedure 07-S-05-310, Attachment I, or in
accordance with the requirement in Procedure 01-S-06-24," Safety and Environmental
Evaluations," Revision 103. Section 6.3.1 of this procedure requires that new
procedures with the potential for adversely affecting environment and operation of
structures or components in the UFSAR be reviewed for safety evaluation applicability.
In this case, the installation and removal of heavy test equipment in the reactor had the
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potential to affect the reactor and the fuelif the equipment were dropped. The licensee
explained that no safety evaluation had been done. The failure to perform the
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procedurally required review for safety evaluation applicability was identified as a third
example of a violation of 10 CFR Part 50, Appendix B, Criterion V
(Violation 50-416/9813-02).
As described above, the lift was conducted through the licensee's work control
,
procedures as a repetitive task. In the root cause analysis evaluation, the licensee
identified that the impact statement on the work package had undergone a number of
changes, but that the affects on design basis and safety evaluation required questions
were answered with "NO." The licensee found that the effectiveness of this barrier was
eliminated by the lack of review of the vendor procedure and the belief that the same
work was done in Refueling Outage 7. Procedure 01-S-07-1," Control of Work on Plant
Equipment and Facilities," Revision 32, Section 6.12.2, required that impact statements
be developed and the work scope clearly identify what the activity will involve, a
programmatic statement identifying special needed attention, effects on the design
basis be identified, and 10 CFR 50.59 application be made.
The impact statement dealt specifically with the performance of the reactor vessel
internals inspection. The work scope did not identify that the work would include a
heavy lift over the reactor vessel. The only reference to procedures in the work
instructions was to approved Westinghouse procedures. No instructions or guidance
were provided for the installation of the equipment. The work package was completed
and approved prior to the arrival of the work instructions for the installation of the shroud
inspection equipment onsite. The inspectors concluded that the inadequate description
of the work and inadequate understanding of the activities that were to occur were a
missed opportunity to apply the regulatory requirements for heavy lifts and to possibly
prevent the event.
E8.6.4 Coordination Between Departments
The inspectors discussed the event with the refuel floor supervisor, a senior reactor
operator, who was on the refueling floor at the time that the event occurred. The
supervisor indicated that, through his review of the engineering evaluation, he thought
that the lift was a light lift, not a heavy lift. The inspectors questioned who was
responsible for the lift. The manager explained that the contractor (the contractor's
refuel floor supervisor) was in charge of the lift.
Procedure 07-S-05-300, Section 6.1.3, requires that all Safety Class 1 lifts on the
208-foot elevation be directed by the refuel floor manager or designee who will have
overall responsibility for safe handling of the load. Procedure 01-S-06-2," Conduct of
Operations," Revision 104, Section 6.7.3, required that the refuel floor supervisor
supervise all refueling activities on the containment and auxiliary building refuel floors,
except core alterations. Section 6.7.6 required that the refuel floor supervisor notify the
shift superintendent before the start of any major evolution. Section 6.7.7 required that
the refuel floor supervisor be present on the 208-foot elevation whenever crane and
hoist activities are conducted and that the supervisor was to supervise all lifting activities
with the containment polar crane. During the root cause analysis investigation, the
licensee found that the shift superintendent was not notified at the start of the heavy lift.
The inspectors discussed this concern with a refuel floor manager who was not onsite at
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the time of the event, but was responsible for the root cause analysis investigation. The
manager explained that there was no definition in the procedure for major evolution and
that operation personnel had been informed of the impending lift at the plan-of-the-day
meeting that occurred early in the morning on the day of the event. The failure to
coordinate with the shift superintendent as required in the procedure was identified as
the fourth example of a violation of 10 CFR Part 50, Appendix B, Criterion V
(Violation 50-416/9813-02).
E8.6.5 Roo. t Cause Analysis Report
The inspectors reviewed the licensee's root cause analysis report. The root causes
identified were that the lifting device was not designed to be used under upset
conditions and that there were no formal controls over system restorations or venting
operations during heavy lifts. Contributing causes identified dealt with: (1) failure to
require review of vendor support procedures, failure to clearly define existing
requirements to review vendor documents, and failure to clearly define the relationship
between heavy loads and lifting devices and the multiple procedures which provided
requirements for lifts on the fuel floor; (2) repetitive tasks did not always meet the quality
requirements in the procedure; and (3) the meaning of positive locking in
ANSI N14.6-1978 was not well defined.
The first root cause identified was attributed to the vendor who supplied the equipment.
Procedure 01-S-03-10, "GGNS Condition Report," defined root cause as the
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fundamental cause(s) that, if corrected, would prevent recurrence of an event or
adverse condition. Designing this lifting device for upset conditions would prevent the
specific event that occurred, but would not prevent other heavy lift events. The
corrective action, having design engineering establish criteria for environmental
consideration and lifting device latching mechanisms and incorporating the criteria in
design documentation procedures, would not address the identified root cause or
prevent recurrence. The problem was that the licensee did not conduct sufficient
engineering review prior to allowing use of the equipment onsite. Changing the design
documentation procedures would not prevent a contractor or vendor from modifying
equipment prior to bringing it onsite or from using unqualified equipment. The licensee
,
already had design requirements in place at the time, but the requirements were not
(
adequately applied. Only one criteria, safety factors, out of a number of requirements
was evaluated. The equipment was not designed in accordance with NUREG-0612
because the load did not meet the criteria of a heavy lift when the equipment was initially
designed. The engineering staff did not question this point or request any evaluation
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which may have been done to qualify the equipment. Had engineering conducted a
thorough, questioning evaluation, questions about the acequacy of the equipment may
have been asked and limitations and precautions for its use put in place.
The second root cause dealt with the lack of controls which should have prevented valvo
manipulations from occurring while a heavy lif t was in progress. The conduct of
operations procedure required that the refuel floor supervisor contact the shift
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superintendent prior to a major evolution. This notification did not occur. The inspectors
questioned whether this f ailure was as a result of an inadequacy within the procedures
or a misunderstanding on the part of personnel as to the seriousness of a heavy lift over
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irradiated fuel. The licensee explained that the term " major evolution" was not defined
and that the refueling floor supervision had informed operations supervision in the plan-
of- the-day meeting that the lift was going to occur at some point that morning. The
inspectors noted that the operations staff in the control room were not given the
opportunity to stop work that changed conditions in the vessel because they were not
notified when the evolution began. The inspectors concluded that the root cause and
corrective action did not accurately reflect the problem because the requirements for
coordination were in place in the plant procedures. Personnel did not adhere to the
requirements.
The inspectors reviewed the first contributing cause and found the f ailure to include the
requirements in the purchase contract was potentially a root cause. if the contract had
detailed the requirements applicable to the lift equipment, the vendor would have had an
opportunity to meet those requirements and prevent the event. If the licensee had
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reviewed the contractor's program to ensure that it met NUREG-0612, there would have
been an additional opportunity to identify problems with the equipment, in this case,
however, the licensee was not aware of the change made to the tooling equipment, so
the contract could not have reflected the additional regulatory requirements. The
inspectors found that the corrective actions identified, changing the contracting program
and enhancing the heavy lift requirements, should address the problem and provide an
opportunity for review in the future, but may not have been effective in preventing the
subject event due to the inability of the licensee to predict the change in the equipment.
The inspectors reviewed the second contributing cause, that the work order did not
provide sufficient detail in the impact statement and the vendor procedure was approved
through approval of the vendor's quality assurance program, not the licensee's review
and approval process. The concern in this case was that a regulatory requirement,
meeting the requirements of NUREG-0612 during heavy load lifts, was not understood
or reflected in the package or in the impact statement. The inspectors noted that this
was the last barrier prior to approval of the package for use. The licensee's corrective
actions included evaluating the use of repetitive tasks to perform nonstandard work and
revising procedures and trair;ing. The inspectors observed that the cause determination
did not include the need for personnel to fully understand the scope of the work and to
accurately reflect the full scope of the work in the impact statement, as required by the
procedure.
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The last contributing cause dealt with the details of the positive locking device, which is
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also related to the first root cause, in that the vendor did not consider upset conditions in
the design of the tool. The corrective action was the same as that identified for the first
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contributing cause. The inspectors noted that, prior to the event, licensee engineering
personnel had not considered whether positive locking devices were used or evaluated
whether the design would be effective.
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E8.6.6 Conclusions
The engineering evaluations prior to and after the event involving the near drop of a
heavy load over the reactor were inadequate and engineering personnel did not have a
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full understanding of the requirements of NUREG-0612 or Grand Gulf's commitments to
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comply with NUREG-0612. The engineering screening for this evaluation was
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inadequate and was a missed opportunity to identify UFSAR requirements and the need
to perfc m a safety evaluation. This was identified as an example of failing to follow
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procedures. Three additional examples of a violation for failure to follow procedures
were identified. The examples included the failure to perform a safety evaluation for the
procedure to perform the heavy lift, failure to ensure that adequate special lift
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procedures were developed, and failure to coordinate the heavy lift with the control
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room. The inspectors concluded the root cause analysis report conducted for the event
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involving the near loss of a heavy load over the reactor was less than adequate. The
conclusions reached were narrowly focused and did not comply with the definitions
provided in the corrective action program. The report failed to identify the failure of
personnel to follow procedures or the f ailure of engineering personnel to understand
regulatory requirements that were in place. Both of these failures contributed to the
event and would have to be corrected to prevent recurrence.
E8.7 (Closed) LER 98-003: Core shroud inspection tool theta drive ring became partially
disconnected from its strongback. The inspectors reviewed the voluntary LER
submitted to document the subject event for the interest of the rest of the industry. The
root causes and corrective actions documented were the same as those identified in the
root cause analysis report. The LER did not address the procedure violations identified
in Section E8.6 or provide new information on the event. The inspectors determined
that this LER could be closed due to the discussion in Section E8.6 and the followup
which will be required as a result of the identified violation.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1
General Comments (71750)
a.
Inspection Scope (71750)
The inspectors made frequent tours of the radiological controlled area and observed
radiological postings and worker adherence to protective clothing requirements.
b.
Observations and Findinas
Personnel followed radiation protection procedures, locked high radiation doors were
locked, and radiation and contamination areas were properly posted with one exception.
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On October 21,1998, the inspectors noted that a high contamination area posted
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around the refuel floor on the 208-foot elevation of containment was posted so that a 2-
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to 3-foot area was not posted. The refuel bridge support leg was in the center of this
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unposted area. The high contamination area was inside a contamination area and the
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posting changed from the high contamination area to the contamination area at the
refuel bridge support. The inspectors discussed the concern with health physics
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personnel. They explained that the refuel bridge had just been moved to that position to
support modifications being made to it and that the posting had probably been changed
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at that point. The inspectors noted that the space between the rail around the pool and
the post was small, but that one could still get through and not see the posted signs.
The health physics personnel posted the area so that there was no opening. Because
the small space was not posted, the inspectors determined that the posting was an
example of a poor posting practice. The inspectors discussed the concern with the
radiation protection superintendent. He reviewed the area and indicated that part of the
open area was marked with tape. The inspectors reviewed the licensee's guidance on
posting and pointed out that tape alone was only appropriate for small spaces and that
the area posted should be such that equipment was fully in or out of the area to ease
operations. The superintendent acknowledged the concern.
c.
Conclusions
With one exception, observed activities involving radiological controls were well
performed. The inspectors identified one poor posting practice where the posting
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around a high contamination area did not meet the licensee's documented guidance.
R4
Staff Knowledge and Performance
R4.1
Reactor Coolant Samole
a.
Inspection Scope (71750)
The inspectors observed the following to verify that plant chemistry was within Technical
Specifications and procedural limits:
06-CH-1821-0-0002, Reactor Coolant Routine Chemistry
06-CH 1B21-W-0008, Reactor Coolant Dose Equivalent Iodine
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b.
Observations and Findinos
On October 7,1998, the inspectors observed reactor coolant routine chemistry and dose
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equivalent iodine sampling and analysis. The technician performing these activities
demonstrated proper concerns for radiological controls and materials handling. The
technician made sure that operations and radiation protection personnel were aware of
the activities being performed. The analyses were performed in accordance with
approved procedures using properly calibrated and standardized laboratory equipment.
The results were entered into the licensee's data tracking system for trending and
analysis. The technician was very knowledgeable of the procedures used and well
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versed on the equipment and analysis techniques used.
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c.
Conclusions
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Routine reactor coolant chemistry and dose equivalent iodine sampling and analysis
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were completed proficiently and in accordtnce with the procedures.
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S1
. Conduct of Security and Safeguards Activities
On a daily basis, the inspectors observed the practices of security personnel and the
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condition of security equipment. Protected and vital area barriers were in good
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condition. The isolation zones were free of obstructions and the protected area
illumination levels were good. The inspectors concluded that the daily security activities
were conducted in a professional manner.
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V. Manaaement Meetinos
X1
Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on November 5,1998. The licensee acknowledged the findings
presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
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ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
Licensee
C. Bottemiller, Superintendent, Plant Licensing
W. Eaton, Vice President, Grand Gulf Nuclear Station
K. Hughey, Director, Nuclear Safety and Regulatory Affairs
C. Lambert, Director, Design Engineering
J. Roberts, Director, Quality Programs
R. Wilson, Superintendent, Radiation Control
J. Venable, General Manager, Plant Operations
INSPECTION PROCEDURES USED
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Onsite Engineenng
Surveillance Observations
Maintenance Observation
Plant Operations
iP 71750
Plant Support Activities
Followup - Engineering
ITEMS OPENED. CLOSED. AND DISCUSSED
Opened
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50-416/9813-01
Failure to install temporary restraining cables on floor grating
(Section O2.1).
50-416/9813-02
Failure to follow procedures resulting in near drop of tool ring
(Section E8.6).
Closed
50-416/9611-01
IFl
Review of the UFSAR description of safety relief va've logic
(Section E8.2).
50-416/9705-02
Lack of leak tests for nonsafety-related to safety-related system
interface valves (Section E8.3).
50-416/9705-06
Test control deficiencies (Section E8.4).
50-416/9705-07
Further review of licensee basis of current flood calculation
(Section E8.5).
50-416/9805-01
IFl
Further review of licensee's investigation into the loss of control of
heavy lif t (Section E8.6).
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50-416/98-003
LER
Core shroud inspection tool theta drive ring became partially
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disconnected from its strongback (Section E8.7).
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Discussed
50-416/9603-01
IFl
Review long-term justification for methodology and assumed valve
factors (Section E8.1).
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