IR 05000285/1990013
| ML20034C948 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 05/17/1990 |
| From: | Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20034C946 | List: |
| References | |
| 50-285-90-13, NUDOCS 9006040061 | |
| Preceding documents: |
|
| Download: ML20034C948 (28) | |
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APPENDIX B U.S.' NUCLEAR REGULATORY CDMMISSION
REGION IV
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h NRC Inspection Report:
50-285/90-13 Lnense:
DPR-40 Docket:
50-285 Liccensee: Omaha Public Power District (OPPD)
h 444 South 16th Street Mall Omaha, Nebraska 68102-2247 Facility Name:
Fort Calhoun Station (FCS)
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Inspection At:
FCS, Blair, Nebraska Inspection Conducted: March i through April 14, 1990 Inspectors:
P. Harrell, Senior Resident Inspector T. Reis, Resident Inspector
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R. Mu111 kin, Project Engineer
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7/1 Approved:
Wr d onstable, Chief, Project Section7
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Division of Reactor Projects Inspection Summary Inspection Conducted March 1 through April 14. 1990 (Report 50-285/90-13)
Areas Inspected:
Routine, announced inspection of:
review of previously identified items; licensee event report followup; monthly maintenance, i
surveillance, security, and radiological protection observations; in-office review of licensee reports; onsite followup of events; and installation and testing of modifications.
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Results: Within these areas, three violations were identified:
failure to meet Appendix R requirements (paragraph 5.a), failure to follow procedures (paragraph 5.c),andfailuretotakeadequatecorrectiveactions (paragraph 5.c).
It appeared that the licensee had not determined the overall effect on
plant safety of the loss of three of four safety-related inverters.
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licensee identified the potential problem on December 1,1989, and did not
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l perform an indepth evaluation until February 28, 1990, when the inspector questioned the validity of the evaluation that had been previously completed.
For this reason, the NRC is concerned with the quality of the review of this licensee-idantified problem (paragraph 5.a).
9006040061 900524 PDR ADOCK 05000285 g
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The licensee failed to provide adequate work instructions regarding the
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removal and storage of radiologically contaminated filters.
In general, the adequacy of instructions continues to be a concern to the NRC since this issue has been identified as a licensee weakness during previous evaluations of licensee performance (paragraph 5.b).
Various plant design problems were identified by the licensee during this
inspection period.
It was noteworthy that the licensee has been aggressive, through their design basis reconstitution efforts, in identifying plant design problems and has been actively pursuing resolution (paragraph 10).
The licensee did not adequately respond to a safety problem identified by
quality assurance personnel involving the use of danger tags (paragraph 5.c).
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DETAILS l
1.
Persons Contacted
- R. Acker, Quality Assurance Auditor
- S. Anderson, Licensing Engineer J. Bobba, Supervisor, Radiation Protection i
- C. Brunnert, Supervisor, Operations Quality Assurance
- J. Chase, Manager, Nuclear Licensing and Industry Affairs
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M. Core, Supervisor, Maintenance
- S. Gambhir, Division Manager, Production Engineering
- J. Gasper, Manager, Training
- W. Gates, Division Manager, Nuclear Operations
- D. Guinn, Licensing Engineer
- T. Herman, Quality Assurance Auditor
- C. Huang, Supervisor, Human Performance Evaluation / Root Cause Analysis
- R. Jaworski, Manager, Station Engineering J. Kecy, Supervisor, Systems Engineering
- L. Kusek, Manager, Nuclear Safety Review Group
- D. Matthews, Supervisor, Station Licensing
- T. McIvor, Manager, Nuclear Projects
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W. Orr, Manager, Quality Assurance and Quality Control
- G. Peterson, Manager, Fort Calhoun Station
- R. Phelps, Manager, Design Engineering J. Sefick, Manager, Security Services P. Septenko, Supervisor, Outage Projects C. Simmons, Station Licensing Engineer F. Smith, Plant Chemist
- S. Sweargin. Engineer, Nuclear Safety Review Group
- J. Tills, Assis+ ant Manager, Fort Calhoun Station
- D Trausch, Super visor, Operations
- S. Willrett, Manager, Nuclear Materials and Administration
- Denotes attendance at the monthly exit interview.
The inspectors also contacted other plant personnel.
2.
Plant Status On February 16, 1990, the licensee commenced a plant shutdown for the 13th refueling outage. On February 26, 1990, the plant was placed in Mode 5 (refueling shutdown). On March 16, 1990, the licensee transferred all fuel assemblies from the vessel into the spent fuel pool to perform maintenance and modification activities on the raw water and component cooling water systems. At the end of this inspection period, the fuel was still stored in the spent fuel pool.
3.
Review of previously Identified Items (92701 and 92702)
The inspectors reviewed the actions taken by the licensee to address previously identified items, as discussed below:
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(Closed) Open Item 285/88201-11:
Inadequate craft training.
This item involved a concern identified with craft training in the area of electrical maintenance. Specifically, craft lesson plans i
did not include training on meter checks and attendant safety I
observers when working on energized equipment.
In response to this issue, the licensee developed Procedure 50-M-100,
" Conduct of Maintenance." The new procedure specifically addressed these issues and the licensee provided training, prior to the 1990 i
refueling outage, for licensee and contractor personnel involved in maintenance activities.
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(Closed) Open Item 285/88201-20:
Control of the calibration of penetration test rigs.
This item was related to an apparent weak program for verifying that the operability of the penetration test rigs used for local leak
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rate penetration testing.
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To address this concern, the licensee issued Procedures CP-IC-295 through CP-IC-303, " Leak Rate Test Panel," for each penetration test rig installed in the plant, to require that the manometer installed on the test rig be calibrated and that the valves on the test rig be checked for leakage prior to each use.
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(Closed) Open Item 285/8903-03: Amendment of the Technical Specifications (TS) to address reactor coolant system (RCS) sampling in a defueled condition.
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This item involved a request made by the Office of Nuclear Reactor Regulation (NRR), in a letter dated October 28, 1988, for the licensee to amend TS 2.1 to specify the sampling requirements for the RCS when the plant is in a defueled condition (i.e., all fuel assemblies have been off-loaded into the spent fuel pool).
On December 1, 1989, the licensee submitted a request for amendment of the TS. On January 31, 1990, NRR approved the request and issued Amendment 124 to change the TS to specify that sampling of the RCS was not required during defueled plant conditions.
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(Closed) Unresolved Item 285/8909-04:
Seismic qualification of a fire protection (FP) line over Emergency Diesel Generator (EDG) 1.
The inspector found two supports removed from the FP line directly over EDG 1 and questioned the seismic qualification of the line. As documented in NRC Inspection Report 50-285/89-44, the licensee submitted a calculation to NRR for review.
The licensee, on December 7, 1989, held a telephone conference with NRR to discuss concerns with the calculation. On February 28, 1990,
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based on the telephone discussion, NRR issued a memorandum that concluded that the pipe stresses and support loads for the system were considered acceptable without the two supports installed, e.
(Closed) Violation 285/8909-05: Modification of a plant system without the use of approved instructions.
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This item was related to the removal of two supports from the FP system without approved instructions. The FP line was located above the generator on EDG 1.
The licensee issued a training " hotline" on May 4, 1989, to maintenance craftspersons to emphasize that hangers, supports, and snubbers cannot be removed without properly documented authorization.
The licensee also provided training, prior to the 1990 refueling outage, for licensee and contractor craftspersons to provide instruction in the maintenance practices at the FCS.
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(Closed) Deviation 285/8909-06:
Testing of fire water curtains.
This item involved the licensee's failure to test the fusible-link valves that were installed on the fire water curtains located at the doorways between the turbine and auxiliary buildings.
In response to this issue, the licensee, in letters dated July 27 and September 15, 1989, requested that the requirement for testing the fusible-link valves be deleted from the Safety Evaluation Report (SER) issued by NRR.
In subsequent telephone conversations between NRR and the licensee, NRR stated that the testing requirement would not be removed from the SER.
NRR also stated that a visual inspection of the fusible-link valves was acceptable since physical testing would result in destruction of the fusible-link mechanism installed on each valve.
The licensee had been routinely performing a visual inspection of
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the fusible-link valves prior to the identification of this apparent problem by the inspector.
The information regarding the visual inspection was provided by the licensee in a letter dated January 17, 1990.
The licensee stated that the inspection was performed in accordance with Procedure OI-FP-6, " Fire Protection System Inspection and Test," as part of the visual inspection performed on the turbine building sprinkler system.
The inspector reviewed Attachment II, " Sprinklers and Piping Inspection," of Procedure 01-FP-6 and noted that the procedure did not specifically require that the fusible-link valves be visually inspected. The inspector interviewed three individuals on the operations staff that performed the visual inspections.
The individuals stated that they routinely inspected the fusible-link valves even though specific instructions were not provided in Procedure OI-FP-6 based on their on-the-job trainin fr
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Although it appeared that the valves were being visually inspected, the inspector was concerned that a requirement for the inspection should be specifically included in Procedure OI-FP-6 to ensure that the inspection was performed and documented. The licensee agreed and revised Procedure 01-FP-6 to require that a visual inspection be performed.
i This item also identified an apparent problem with no water curtain being installed between the fan room and Room 81.
In response to this issue, the licensee denied the deviation.
The denial was based
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on the existence of a fire curtain between the fan room and the
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turbine building.
The inspector reviewed the licensee's denial and concurred that the installation of a fire curtain between the fan room and turbine building met the intent of the SER.
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(Closed) Violation 285/8913-01:
Cable tray covers were not being reinstalled.
This item involved the failure of licensee personnel to replace cable tray covers after removal for modification activities.
To address this problem, the licensee issued, on June 19, 1989, a
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training " hotline" to notify electrical craftspersons of the requirement to replace tray covers.
The licensee also provided training, prior to the 1990 refueling _ outage,-for all contractor and licensee personnel to instruct them on the FCS maintenance practices.
In addition, Procedure M-100, " Conduct of Maintenance,"
was revised to require that tray covers not be removed unless specified by a maintenance work order (MWO) or an approved modification package.
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(Closed) Open Item 285/8913-08:
Licensee submitte' ' 3ctions to l.
increase the reliability of the 161-kV offsite pos -
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On March 4, 1989, the licensee lost one of two availeole offsite power sources.
The loss of the 161-kV offsite power source placed I
the plant in an abnormal situation because the loss of the 345-kV line, the other offs'te supply, would.cause power to be lost to the reactor coolant pum',s since the pumps are normally supplied by
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Thus, the plant would be placed in the
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E natural-circulation mode of operation if a reactor trip occurred while the 161-kV supply was out of service.
l The licentee stated that a reliability analysis would be performed to deterr;ine what actions, if any, would be taken to increase the reliabGity of the offsite power sources. The licensee, in a letter datad December 22, 1989, submitted the results of their 161-kV power supply reliability review. The results were as follows:
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The entire 161-kV line from the Blair, Nebraska, substation to
FCS was inspected. The results indicated that all power pole strengths fell within the acceptable range for structural capacity. None of the poles required replacement cue to strength deterioration.
The licensee treated all the wooden poles to ensure that there
was a proper level of preservative in each pole.
OPPD will consider the use of antiga11oping devices on the
conductors.
The abcve actions satisfied the comitment made by the licensee to the NRC.
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(Closed) Violation 285/8933-01:
Providing personnel monitoring devices (TLD) to personnel in the energency response organization (ERO).
This item involved the licensee's failure to provide permanent TLDs to all personnel in the ERO that are required to report to onsite locations in an emergency, as required by the licensee's NRC-approved energency plan.
To address this item, the licensee took the following actions:
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Provided all personnel in the ERO with permanent TLDs.
- Provided a supply of TLDs in the security area for issuance to
personnel not in the ERO that may respond to an onsite emergency.
Issued an internal memorandum (RS-EP-90-040) that documented
personnel assignments to the ERO and the requirement that all individuals be provided with a TLD.
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(Closed) Violation 285/8933-02: Announcement of the arrival of an inspector.
This item involved the announcement of the arrival of the inspector via the intercom radios used by security personnel.
To address this violation, the licensee took the following corrective actions:
Issued, on September 22, 1989, a bulletin to all security
personnel that restated the regulatory requirement that announcement of the arrival of an inspector was prohibited.
Issued, on October 16, 1989, a memorandum to all badged
personnel that stated announcement of the arrival of an inspector was not allowed.
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Revised the general employee training cou so to include a discussion regarding the announcement of the arrival of an inspector.
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(Closed) Open Item 285/8944-01:
Instructions for work on redundant equipment.
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This item involved a concern where licensee procedures were not i
clear on the requirement to allow maintenance to be performed on
only one train of redundant safety equipment at a time.
The licensee agreed with the observation an:i, as an improvement,
revised Procedure 50-0-20, " Equipment Tagging Procedure," to
specifically prohibit such action unless allowed by the TS.
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(Closed) Open Item 285/8944-02:
Linkage for Valves LCV-383-1 and LCV-383-2 (the safety injection and refueling water tank (SIRWT)
outlet valves).
i This open item involved the apparent lack of a retaining device on i
l the handwheel linkage for Valves LCV-383-1 and LCV-383-2. These I
valves were designed with two mechanical linkages. One linkage i
l engages the handwheel to the valve stem and the other engages the I
air operator to the valve stem.
The linkages were designed such j
that the handwheel linkage is normally disconnected and the air l
operator normally connected.
Due to the design of the linkage, the
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possibility existed that the handwheel linkage could inadvertently become engaged when the salve stem was rotated by the air operator.
If both linkages become engaged, the valve would not be able to move since the operator cannot supply sufficient force to rotate the hendwheel and its installed gear box.
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In response to this open item, the licensee stated that a review would be performed to determine if a linkage-retaining device should be t
installed on the valves, i
The system engineer reviewed the construction of the valves and identified that a retaining device was installed. The device, a spring and ball bearing arrangement, prevents engagement of the handwheel linkage, m.
(Closed) Violation 285/8948-01:
Inoperable component cooling water (CCW) heat exchangers.
This violation involved a condition where two of four CCW heat exchangers were inoperable for greater than a 7-day period. TS 2.3 requires that the plant be shut down if such a condition exists for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Licensee analysis indicated that the design heat loads could have been removed by the remaining two operable heat exchangers. This l:
condition was caused by inadequate administrative controls.
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The licensee took the following corrective actions:
Revised Procedures $0-0-20 " Equipment Tagging Procedure," and
50-0-29, " Conduct of Operations," to require that equipment be functionally tested following tag clearance regardless of the reason for the tag-out.
- Incorporated the lessons learned from this event into lesson Plans 4-43-2, " Component Cooling Water," and 4-2-12. " Valve Principles." A video tape was developed to illustrate the operation of these engagement mechanisms on valves that have differences between their manual and automatic modes of operation. The appropriate operations personnel have been provided training.
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(Closed) Inspector Inspector Followup Item 285/8950-03:
Issuance of a request by the licensee for amendment of TS 2.2.
This item was related to the submission of a TS amendment request by the licensee to clarify an apparent discrepancy between TS 2.2 and 2.3.
TS 2.2 required that at least 10,000 gallons be maintained in the SIRWT; whereas, TS 2.3 required a minimum of 283,000 gallons.
On January 24, 1990, the licensee submitted a TS amendment request to specify that the TS 2.2 requirement applies only when the reactor is suberitical.
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(Closed) Followup Item 285/8950-04:
Correction of an error in TS 3.16.
In a letter dated February 1,1990, the licensee issued an amendment request for TS 3.16 to correct the typographical error identified in the licensee's original application for amendment of the TS.
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(Closed) Open Item 285/9002-01:
Inclusion of ANSI N45.2.9 requirements in procedures.
This item involved a condition where licensee's maintenance and modification procedures failed to consider requirements for records storage per ANSI N45.2.9.
The licensee revised Procedure 50-G-58, " Control of Fire Protection System Impairments," to require that Form FC-1142, " Fire Protection Impairment Permit," be completed prior to dismantling any fire protection equipment associated with the records storage vault.
This form requires approval of the fire protection system engineer prior to degrading any fire protection equipment, q.
(Closed) Open Item 285/9002-02: No procedural control for opening the auxiliary building rollup door.
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The inspector noted that the licensee lacked a procedure for controlling the opening of the rollup door from the radiologically controlled area inside the auxiliary building to the site environment.
The licensee generated memoranda to the appropriate personnel in operations, security, and health physics on the procedure to be followed when opening the door. On February 28, 1990, Procedure RP-AD-200, " Radiation Protection Administration Procedure," was revised to address this issue.
l The actions taken by the licensee in response to previously identified items appeared to be conservative and provide adequate controls to prevent recurrence.
Licensee management involvement in resolving the issues was apparent.
4.
Licensee Event Report (LER) Followup (92700)
The following event reports were reviewed by the inspectors to verify that reportability requirements were fulfilled and corrective actions were accomplished to prevent recurrence:
a.
(Closed) LER 88-026 reported an event where, during the 1988 refueling outage, EDG 2 was automatically started due to a technician
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replacing a cover on a relay, after calibration had been completed, and inadvertently tripping the relay.
Shutdown cooling flow was not lost; therefore, the loss of power did not affect safe plant operations.
The licensee stated that Procedures CP-SP-1 and CP-SVR-1, both titled
" Station Relaying," would be updated before the 1990 refueling outage to ensure that the procedures provided adequate directions to the technicians.
Since the issuance of LER 88-026, the licensee revised its calibration procedure system.
As a result, Procedures CP-SP-1 and CP-SVR-1 have been deleted and approximately 100 procedures were generated to replace the two procedures.
The inspector reviewed a sampling of the newly created procedures by reviewing of Procedures SP-CP-08-161-AR, SP-CP-08-161-IF0, and SP-CP-08-G1-SAM.
Based on review of these procedures, it appeared that the licensee had taken appropriate actions to address this event.
b.
(Closed) LER 88-037 reported an event where the FP system in the air compressor bay was inoperable due to the isolation of that portion of the system.
The cause of the event was determined to be a lack of procedural guidance in the communication of design basis concerns between design engineering and the plant staff.
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actions included providing enhanced administrative controls to improve communications and correct weaknesses in the control of FP impairments.
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(Closed) LER 89-020 reported an event where the licensee failed to comply with the TS limiting condition for operation for the CCW heat exchangers.
The followup of this event is discussed in paragraph 3.m of this report.
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(Closed) LER 90-004 reported an event where the main steam safety valves, during surveillance testing, were found not to comply with the requirements stated in TS 2.1.6(3) for their lif t setpoints.
Details of the followup performed by the inspector of this event are
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provided in paragraph 10.c.
Based on the reviews performed by the inspectors, it appeared that the licensee had taken timely actions to implement controls to prevent recurrence of the identified events.
5.
Operational Safety Verification (71707)
The inspectors conducted reviews and observatiuns of selected activities to verify that facility operations were performed in compliance with the appropriate regulatory requirements.
The inspectors identified the i
following items:
a.
On July 20, 1989, a licensee contractor developed and implemented a
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self-initiated safety system functional inspection (SSFI) of the 120-Vac vital instrument power system.
The contractor subsequently published the results of the SSFI on December 1,1989.
The report included Inspection Observation FC-E-04 which stated that a fire in the west switchgear room could result in the loss of three of four safety-related inverters that supply power to the 120-Vac instrument
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buses.
l The east and west switchgear rooms are separated by a barrier with a
3-hour rating.
The west switchgear room contains Inverters B and D, I
and the east switchgear room contcins Inverters A and C.
This physical configuration establishes the required separation between redundant (Inverter A and C for Train A, and Inverter B and D for
Train B) safe shutdown equipment.
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Inverters C and D power instrumentation and controls in the control
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room and on the alternate shutdown panel (ASP) located on the
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upper-level electrical penetration (VLEP) room.
The licensee determined that a fire in the ULEP room could cause a fault in the cables from Inverters C and D and result in a loss of power from the inverters. The loss of inverter power could, in turn, make I
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control room instrumentation inoperable.
To eliminate this concern, the licensee, under Modification Request (MR) FC-84-119, added two external circuit breakers (EE-6C and EE-6D) on a common column in the west switchgear room to protect against an Inverter C and D power loss.
By procedure, Breakers EE-6C and EE-60 would be opened to isolate the cables feeding the ASP so that a fault would not i
affect the inverter output power.
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The SSFI determined that Breakers EE-6C and EE-6D were wired
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directly to the inverter output, bypassing the inverter output circuit breakers.
In this configuration, a short circuit in the cables for Breakers EE-6C and EE-60, due to fire damage, could result in Inverters C and D entering a current-limiting condition and the output voltage dropping below acceptable limits.
In addition, Inverter B could also be damaged by a fire in the west switchgear room.
The inspector reviewed the contre.s'.or's report and inspected the installation of Breakers EE-6C er" EE-6D.
Since the distance between Inverter 8 and the cables for Breakers EE-6C and EE-60 was approximately 10 feet, the inspector concluded that an exposure fire in the west switchgear room could render safety-related Inverters B, C, and D inoperable.
In response to SSFI Inspection Observation FC-E-04, tni licensee issued MWO 886773 to measure the loads at the 120-Vac distribution panels during power ascension at 2 percent, 30 percent, and above 80 percent power.
The licensee concluded that the maximum measured load was approximately 34 amps on Inverter A and 12 amps on Inverter B, when the plant was at 30 percent power. The combined load of 46 amps was found to be within the 62.5-amp capacity of Inverter A (the unaffected inverter); therefore, the licensee stated that Inverter A was capable of supplying all loads normally supplied by Inverters A and C.
In addition, the licensee concluded that Procedure A0P-16 " Loss of Instrument Bus power," addressed the transfer of loads from a dead bus to a live bus.
The inspector noted that the licensee's conclusions appeared to be weak, based on the following:
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No analysis was available to determine what plant perturbations could result before the loads on Inverter C were manually transierred to Inverter A.
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Procedure AOP-16 addressed the loss of one of the four l
inverters, but did not address the loss of three inverters, as
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could potentially be the case.
The licensee, by internal Memorandum PER-FC-90-919, dated February 28, 1990, responded to the inspector's concerns. The memo stated that these concerns had been previously addressed by the l
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existing Updated Safety Analysis Report (USAR), Appendix R safety evaluation reports issued by the NRC, and existing procedures.
The memo also stated that additional details and clarification regarding the loss of inverters were needed in Procedures AOP-16 and OI-EE-4 and Paragraph 8.3.5.3 of the USAR.
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The memo further stated that the FCS design basis included safe shutdown for single failures, including the loss of one of two DC buses which, in turn, would cause the loss of two of four instrument inverters. Also, the FCS has been evaluated as meeting the requirements of Appendix R to 10 CFR Part 50 for the ability to achieve and maintain safe shutdown capability following a fire with
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certain exemptions approved by the NRC.
The exemption specified by
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the licensee was granted by the NRC on July 3,1985, to cover separation criteria in the switchgear rooms.
The inspector reviewed the NRC letter, dated July 3, 1985, that granted exemptions to the FCS.
The letter stated that the licensee requested an exemption from Section III.G of Appendix R to the extent that it required that systems associated with redundant shutdown divisions be completely separated by a continuous 3-hour
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fire rated barrier.
The letter specified a concern in the level of fire protection in the west switchgear room, where unprotected 4160-volt bus ducts in the perimeter walls could cause fire propagation through the wall and affect redundant shutdown divisions in the east switchgear room.
The NRC granted an exemption to the protection of the 4160-volt bus ducts with 3-hour fire rated barriers based on the following:
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The east and west switchgear rooms were protected by area-wide automatic fire detection and fixed fire protection systems.
The fire detection systems provided the staff with reasonable assurance of early fire awareness and response by the plant fire brigade.
- A fire would net tse expected to propagate rapidly, or with a high release rate, due to the limited combustibles in these areas.
If rapid fire propagation occurred before the arrival of the brigade, the fire suppression syste'm would activate to control the fire.
The inspector concluded, in conjunction with NRR personnel, that the exemption granted on July 3, 1985, did not pertain to the condition where a fire could render three inverters inoperable.
Exemptions to Appendix R are granted on a specific case-by-case basis and cannot be used as a blanket exemption for an entire fire area as it appeared that the licensee was attempting to do.
Section III.G.2 of Append;x R to 10 CFR Part 50 states, in part, that where redundant trains of systems necessary to achieve and
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maintain hot shutdown conditions are located within the same fire area, one of the following means of ensuring that one of the redundant trains is free of fire damage shall be provided:
Separation of cables and equipment of redundant trains by a fire barrier having a 3-hour rating,
Separation of cables and equipment of redundant trains by a horizontal distance of more than 20 feet with no intervening combustible or fire hazard, or
Enclose the cable of one redundant train in a fire barrier having a 1-hour rating.
The cables that run from Inverters C and D are enclosed in 1-inch diameter conduits.
These conduits do not constitute either a 1-hour or a 3-hour rated fire barrier.
In addition, the distance between redundant trains is less than 20 feet.
Thus, the plant configuration where a single fire could render three of four safety-related inverters inoperable is considered an apparent violation.
(285/9013-01)
Generic Letter 86-10, published on April 24, 1986, provided interpretations of Appendix R.
One interpretation stated that, where the licensee chooses not to seek prior NRC review and approval of a fire area boundary, an evaluation must be performed by a fire protection engineer and retained for future NRC audit.
At the time of this inspection, the licensee had completed an evaluation as to the affects of losing three inverters.
However, this evaluation only looked at the load capability of the unaffected Inverter A versus the total safety-related loads on that train. The evaluation did not consider the operational aspects of the effects the loss of
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equipment on Inverter C would have on the plant until they could be
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transferred to Inverter A.
Thus, the evaluation the licensee performed was considered to be weak.
In response to this problem, the licensee stated that a fuse (located in the east switchgear room) would be installed in the
cable from Inverter C (located in the east switchgear room) and i
Breaker EE-6C (located in the west switchgear room) to provide fault
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protection in the event that a fault in the cable occurred during a fire in the west switchgear room. At the exit meeting, licensee management stated that the fuse installation would be completed L
prior to exceeding an RCS temperature of 300'F, the point where the l
TS require the inverter to be operable, when starting up from the current refueling outage. This position is acceptable to the NRC
staff.
In addition, the licensee plans to address this issue in a
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revision to the USAR.
b.
During a plant tour on February 17, 1990, the inspector noted that the licensee had stored 40 spent, high efficiency particulate L
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air (HEPA) filters in Room 69, an area containing safety-related i
equipment. The filters were removed during routine filter replacement activities and had been stored in Room 69 for approximately 4 days in polyethylene bags.
The 4-day period was established by the health physics survey information that had been written on the bags.
Some of the filters had radiation levels of 4-6 mR/hr indicating internal contamination.
Section 3.3.5 of Procedure 50-G-6, " Housekeeping," implemented in accordance with the requirements of TS 5.8.1 required that spent HEPA filters be transferred immediately to closed containers when i
removed from inservice use as the HEPA filters represent a source of airborne activity when ignited.
The licensee's failure to immediately place the HEPA filters in closed containers is an apparent violation.
(285/9013-02)
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Upon notification by the inspector of this problem, the licensee immediately removed the HEPA filters from Room 69 and placed the filters in Room 27.
The FP engineer designated Room 27 as an appropriate storage location since, unlike Room 69, it did not contain combustibles or ignition sources. Also, Room 27 was a low traffic area which was locked.
The licensee removed the HEPA filters in accordance with the instructions provided by MWO 900445 that stated that the work should j
be accomplished in accordance with Procedure MP-HEPA-1,
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" Installation and Inspection of HEPA Filters." Neither the MWO nor Procedure tiP-HEPA-1 provided directions on how to properly dispose of HEPA filters.
The licensee subsequently revised Procedure 50-G-6 to state that HEPA
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filters must be stored in closed metal containers within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> when removed from inservice use.
The licensee issued Hotline 90-306 to the appropriate personnel to ensure that the individuals were made
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aware of the newly established requirement. The 11:ensee also revised Procedure MP-HEPA-1 to provide instructions on the proper method for disposal of HEPA filters.
However, the inspector noted that several additional procedures had been issued to provide l
instructions for replacement of HEPA and charcoal filters and the
licensee had not updated these procedures.
c.
In February 1989, NRC Inspection Report 50-285/88-201 documented a concern with the control of danger tags. The concern was related to the removal of a breaker from a motor control center (MCC) cubicle with the danger tag remaining installed on the breaker in lieu of
leaving the tag installed on the cubicle door.
The concern was documented as Open Item 285/88201-12.
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To address this concern, the licensee revised Procedure 50-0-20,
" Equipment Tagging Procedure," to require that the danger tag remain on the affected equipment instead of being removed when a component is removed.
On March 23, 1990, during a plant tour, the inspector noted that two safety-related breakers (for Valves HCV-347 and HCV-268) had been removed from MCC 4C2 and 3C2, respectively, for testing, and the danger tags were still installed on the breakers.
The inspector verified that a duplicate tag was not installed on the MCCs.
During review of this event, the inspector found that the licensee's quality assurance (QA) organization, on March 20 and 21,1990 (2 days before the inspector identified the tagging problem), identified tagging problems and notified the plant manager of the problems identified on both days. Actions were initiated by plant management to address the identified problems with tagging requirements; however, it appeared that the actions were apparently insufficient in that additional problems were identified after the actions had been completed.
i The licensee failed to adequately correct a significant condition adverse to quality in that the problems identified with the control of danger tags recurred after the licensee had implemented corrective actions.
This is an apparent violation.
(285/9013-03)
I In response to this apparent problem, the licensee initiated a detailed review of the tags installed in the plant.
The licensee
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I identified three additional examples where safety-related breakers were removed from an MCC with the tag attached to the breaker.
In addition, the licensee identified one instance where a tag was t
l installed on a safety related breaker that specified that the I
breaker should be in the "off" position and the breaker was found in the "on" position.
To address this problem, the licensee halted work in the plant and required all badged personnel to attend a special training class on i
the requirements contained in Procedure 50-0-20.
This appeared to address the short-term corrective action for this problem; however, long-term action had not yet been implemented in that the licensee had
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not previously provided training to craftpersons on the proper control of danger tags.
d.
On March 16, 1990, Cooper Nuclear Station (CNS) identified an apparent problem with the procurement of flexible hoses used in the EDG starting air and other safety-related systems.
The hoses, manufactured by the Crawford Valve Company, had been procured by CNS from the Omaha Valve and Fitting Company.
CNS determined that the hoses were used in a safety-related application but had been supplied
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17 by a subcontractor that supplies only comercial-grade hoses.
Therefore, the qualification of the hoses for use in a safety-related system appeared to be questionable.
On March 19, 1990, the licensee was inforned of the )otential problem it'< the, apparently, nonqualified flexible loses since the licensee,
known to have purchased hoses from the Omaha Valve and Fitting Company. The licensee initiated an evaluation to determine if the flexible hoses purchased from the company were installed in safety-related systems.
Prior to the end of this inspection period, the license-had not completed their evaluation. The Division Manager, Proow cion Engineering stated that the evaluation would be completed prior to startup from the current refueling outage.
6.
Monthly Maintenance Observations (62703)
The inspectors observed selected station maintenance activities on safety-related systems and components, as discussed below; a.
On March 6,1990, the inspector observed work in progress on MR-FC-89-68 "Al-09 Indications." This modification involved the
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rewiring of some indications on AI-179, the alternate shutdown panel.
During design basis reconstitution efforts, the licensee noted that two indicators on AI-179 were powered by Inverter C when they should receive their power directly from EDG Bus 2.
The work was found to be accomplished in accordance with the approved modification package, b.
On March 6,1990, the inspector observed work in progress toward MR-FC-87-36, " Repair Fire Dampers." No problems were noted during the observations.
c.
On March 6,1990, the inspector observed elenrical maintenance personnel inspect Bus lA3 per Procedure EM-PM-EX-1400, "4160-Volt Switchgear Inspection." The inspector verified that appropriate danger tags had been installed locally and in the control room.
During observation of the maintenance activities performed by licensee personnel, the inspectors observed that the maintenance evolutions were performed in accordance with the appropriate regulatory requirements.
7.
Monthly Surveillance Observations (61726)
The inspector observed TS-required surveillance testing on safety-related systems and components, as discussed below; a.
On April 4, 1990, the inspector observed portions of the performance of Procedures OP-ST-SI-3001 " Safety Injection System (SIS)
Category A, B, and C Valve Exercising Test," and OP-ST-CA-3001,
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" Compressed Air Category A Inservice Valve Exercising Test." These procedures were newly formatted procedures and were being performed for the first time. The tests are performed each cold shutdown and are designed to meet the licensee's commitment to ASME Section XI, Subsection IWV.
For the portions of the test observed, which included exercising Valves HCV-304, HCV-305, and HCV-1749, the requirements of ASME Section XI were met. The licensed operator conducting the test performed the tests as written.
It appeared the
new procedures had been properly validated prior to issuance, b.
On various days throughout this inspection period, the inspector observed work per Procedure MM-ST-DG-0001, " Emergency Diesel Generator Refueling Outage Inspection for EDG 1."
The procedure included perfurming preventive maintenance and indepth internal inspections of the EDG. The procedure was discussed with the lead craftsman and no problems were noted.
Based on the observations made by the inspector, it appeared that the licensee was adequately implementing the surveillance testing program.
8.
Security and Radiological Protection (RP) Observations (71707)
Within this inspection area, the inspectors made the following observations:
a.
The inspectors toured the plant vital and protected areas to verify that the licensee's NRC-approved physical security plan was being implemented.
During the tours, the inspectors noted that the security force was adequately performing their duties.
b.
On March 31, 1990, the inspector noted that a piping penetration from Room 18, a radiologically controlled area (RCA), to Room 19, a l
noncontrolled area, had been breached.
The inspector noted that the l
licensee had not posted the greater-than-12-inch opening between i.
Rooms 18 and 19 with appropriate radiological postings. The
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inspector's review identified that the Supervisor, Radiological
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Services had left explicit instructions with his subordinates to post the area once the barrier was breached but that these instructions had not yet been implemented.
The piping had been removed from the penetration for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> prior to the inspector's observation. However, security had posted a continuous watch of the penetration since it constituted a vital area breach.
Given the compensatory actions taken by security, there was no chance of inadvertent entry into the RCA.
The purpose of radiological postings is to prevent inadvertent entry; therefore, no safety significance with the licensee's failure to promptly post the area was identified.
This appeared to be an isolated incident of an action item being neglected in the licensee's shift turnover policies; therefore, the licensee agreed to examine its turnover proces.
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c.
During plant tours, the inspector noted that RP supervisory personnel routinely toured the RCA to verify that RCA postings and barriers were adequate and to oversee the performance of health physics personnel.
Based on the observations made by the inspectors, it appeared that the licensee was adequately meeting regulatory requirements.
It was noteworthy that RP supervisory personnel were providing oversight of ongoing RP activities in the RCA.
9.
In_-OfficeReviewofReports (90712 and 90713)
NRC personnel identified a 10 CFR Part 21 report submitted by a vendor that appeared to be applicable to the licensee's facility.
The resident inspector provided a copy of a letter, dated January 5, 1990, from the EGS Corporation (Region IV Log No. P21-90-05) to the station licensing engineer on February 20, 1990, for review of applicability by the licensee. The letter addressed the use of grommets in conduit seals.
10. Onsite Followup of Events (93702)
During this inspection period, the inspectors reviewed the following events:
a.
On February 16, 1990, the licensee identified, during reconstitution of the design basis, that the stresses in the auxiliary feedwater (AFW)
line exceeded the allowable stresses specified in the USAR.
The licensee identified that the previous calculation performed to analyze the stresses had not considered the forces, created due to thermal anchor motion (TAM), that are developed when the steam ge.erator heats up to operating temperatures.
Due to the forces that are developed during heat up, the licensee determined that the AFW lines, where the lines connect to the steam generators, were overstressed.
In subsequent reviews of other stress calculations, the licensee identified other piping connections where TAM-induced forces had not been considered, resulting in overstressed conditions.
The piping connections identified by the licensee included safety-injection connections to the RCS, blowdown lines connected to the steam generators, and the main steam (MS) line connection to the steam generators.
The licensee is discussing the issue of TAM-induced stresses with NRR personnel to resolve the problems prior to plant startup from the current refueling outage.
The licensee issued LER 90-003 to document the details of this issue.
Review of the actions taken by the licensee will be performed during closcout of the LE V
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4 b.
On February 17, 1990, the licensee experienced a fire in the clothes dryer, located in the laundry room inside the RCA, used for drying anticontamination clothing. At the time of the fire, the dryer was not in operation. The licensee requested assistance from the Blair, Nebraska, fire department; however, the licensee's fire brigade had extinguished the fire prior to arrival of the Blair fire department.
The fire was contained in the immediate area of the dryer and did i
not affect the operation or operability of any safety-related
equipment.
The inspector reviewed the licensee's actions taken in response to the fire. The actions appeared to be adequate in that the onsite i
fire brigade responded to the fire in a timely manner, the fire was extinguished in less than 10 minutes, and, as a precautionary
measure, the RCA was evacuated of all personnel.
No problems were
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identified during review of this event.
c.
On February 17 and 18,1990, the licensee tested the main steam safety valves (MSSV) and found that the setpoint of six of ten MSSVs did not comply with the required range of il percent of the nameplate data, as stated in TS 2.1.6.
The as-found setpoints ranged up to +2.3 percent above the nameplate rating. The TS requires that eight of ten MSSVs be operable (i.e. within the required setpoint range) or the plant be placed in Mode 3.
At the time the MSSV setpoints were found to be out of tolerance, the plant was in Mode 3.
On September 8, 1989, the licensee submitted a request for amendment of the TS to change the setpoint range of the MSSVs from 11 to +3/-2 percent of the nameplate data. The licensee performed an analysis to support the requested change and the analysis indicated that the MSSVs could fulfill their intended safety function if the setpoint was within the +3/-2 percent range.
Therefore, the licensee concluded that the as-found MSSV setpoints were bounded by the analysis and did not reduce the margin of safety provided by the USAR.
1he request for amendment of the TS was still under review by NRR.
Based on the licensee's existing analysis, it appeared that the inoperable MSSVs did not adversely affect plant safety.
The nonconforming MSSVs were calibrated in accordance with Procedure IC-ST-MS-3002, " Main Steam Safety Valves Verification of the Lift Point Using Furmanite's Trevitest Equipment," to lift within a range of 1 percent, as required by the TS.
d.
On February 26, 1990, the licensee experienced an inadvertent loss of offsite power due to the bumping of the relay used to detect ground faults on an electrical bus normally supplied by offsite power. At the time of the event, the plant was in the shutdown cooling mode of operatio _
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1 In response to this event, the licensed operators energized a vital bus with the EDG 2 and reestablished shutdown cooling within 2 minutes. All equipment performed as designed in response to the
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event.
t A detailed review of this event was performed by a specialist from the Region IV office.
The details of the review are provided in NRC Inspection Report 50-285/90-21.
e.
On February 26, 1990, the licensee experienced an inadvertent
initiation of a containment isolation actuation signal (CIAS) which, in turn, initiated a ventilation isolation actuation signal (VIAS).
The VIAS automatically secured the containment purge that was in operation at the time of the event.
All equipment affected by the VIAS functioned normally. No equipment was affected by the CIAS
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since the plant was in the shutdown cooling mode of operation and the equipment had been placed in override to prevent operation.
The CIAS was initiated when a craftsperson inadvertently bumped a relay while working in a control room cabinet.
The operations staff
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reset the signal and restored the containment purge.
Routine followup will be performed by review of LER 90-002, generated by the licensee to document the corrective actions that will be taken to address this event, f.
In March 1989 the licensee identified, during design basis
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reconstitution efforts, that the dead weight loads for the main feedwater (MFW) piping upstream of the MFW containment isolation valves exceeded allowable values.
To resolve this problem, the
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licensee installed, by direction of temporary modification instructions, a support under each feedwater regulating valve.
To t
make the temporary modification a permanent modification, the licensee continued to review historical documentation to verify that the MFW lines were adequately supported.
On February 28, 1990, the licensee notified the inspector that the MFW lines did not meet the design basis requirements stated in Appendix F of the USAR.
The design basis stated that the entire length of MFW piping in the main steam header room (Room 81) should be designed and installed as Seismic Class I piping. The piping was designed and installed as Seismic Class I from the MFW containment isolation valves to the steam generators; however, the piping upstream of the MFW isolation valves in Room 81 was designed and installed as Seismic Class II piping. As a result of this discovery, the licensee stated that 13 line supports for the MFW piping would be overloaded as-a result of a design basis earthquake.
Because the supports exceeded their design capacity, the licensee
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stated that the high-energy line break criteria was exceeded in locations not previously analyzed.
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1 On March 22, 1990, the licensee notified the inspector that the same type of problems with the seismic qualification of the MFW line, as
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discussed above, also applied to the MS line installed in Room 81.
The licensee stated that the apparent inadequate installation of supports on the MFW and MS lines would be resolved prior to plant startup from the current refueling outage.
The licensee is holding
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ongoing discussions with NRR to resolve this issue.
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To document the details of the seismic installation of the MFW and MS piping, the licensee issued LER 90-007.
Routine followup will be i
performed on this issue during review of the LER.
g.
In January 1990 the licensee performed an air flow test for the spent fuel pool (SFP) area in the auxiliary building (AB).
The test i
was conducted to verify that air in the vicinity of the SFP was
passing through the SFP charcoal filter (VA-66) based on a concern i
identified by a systems engineer.
Test results indicated that air arijacent to the SFP was not passing through VA-66. Based on the test results, the licensee determined that the plant was not within j
the design basis established by Section 14.18 of the USAR that assumes, in the event of a fuel handling accident (FHA), that all air
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in the vicinity of the SFP passes through VA-66.
The test results indicated that the majority of air passing through VA-66 was drawn into the AB from outside via the space around the rollup door installed in the AB wall.
Because little air was drawn from the SFP area, the USAR analysis for an FHA in the SFP was
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invalid. The licensee placed a hold on SFP activities to prevent spent fuel movement.
The licensee notified the inspector of the test results on February 26, 1990.
To address this apparent design basis inadequacy, the licensee issued Safety Analysis for Operability (SAO)90-002 that states,
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even though VA-66 does not perform as intended, that the analysis generated for an FHA in containment envelopes the consequences of an FHA in the SFP.
The FHA for containment assumes that 176 fuel rods in a fuel assembly would fail; whereas, the FHA for the SFP assumes
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l that only one row of fuel rods (14) in a fuel assembly fail.
For the l
containment FHA, the offsite dose does not exceed the limits I
specified in 10 CFR Part 100 and the dose to the control room
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l operators dor $ not exceed the limits specified in Standard Review i
Plan 6.4.
Based on this discussion, the licensee concluded that an FHA in the SFP would not exceed any regulatory requirements.
l Therefore, SAO 90-002 concluded that no actions were required to L
modify the SFP ventilation system to ensure that the air adjacent to i
l the SFP passed through VA-66.
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L The inspector forwarded SA0 90-002 to NRR for review.
In discussions
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with NRR, on March 1, 1990, the following was established:
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Approval was provided for the movement of spent fuel from the i
reactor vessel to the SFP and back to the vessel for this i
outage only.
$hifting of the fuel within the SFP will not be allowed upon conclusion of the current outage.
- The issue regarding the capability of VA-66 to perform its
intended safety function was an unreviewed safety question; therefore, the licensee must perform the appropriate modifications to VA-66 to reestabitsh the design configuration or obtain NRC approval prior to moving spent fuel in the future.
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was enveloped by the analysis performed for an FHA in containment; therefore, the conclusion that no licensee action
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was required, as stated in the SAO, was not valid, i
The above information was provided to licensee management at the exit meeting. The Division Manager, Nuclear Operations stated that administrative actions would be taken to ensure that no fuel would be moved until this issue is resolved with NRR.
The licensee issued LER 90-005 to provide details of this problem.
Routine followup of the LER will be performed to resolve this issue.
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h.
On March 6, 1990, the licensee notified the inspector of an inadvertent actuation of the pressurizer pressure low signal (PplS)
caused by a craftsperson removing a fuse on a 120-Vac instrument bus.
During removal of the fuse, the craftsperson caused.a short on the bus which resulted in Inverter A transferring from the normal to the bypass mode. The transfer of the inverter caused the PPLS to become unblocked and initiate other engineered safety features (ESF)
signals.
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At the time of this event, the plant was in the shutdown cooling mode with the RCS depressurized.
To prevent actuation of ESF signals due to no pressure in the RCS, the PPLS is manually blocked.
If the block is removed, then the PPLS will initiate a safety injection actuation signal (SIAS) and CIAS which,-in turn, will actuate the appropriate equipment.
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In this event, no equipment was affected by the SIAS since the
licensee had removed fuses to prevent equipment actuation.
The CIAS
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caused the containment purge, that was in progress at the time of the event, to be secured. All equipment functioned as designed.
The licensee reset and reblocked the PPLS and reinitiated the containment purge.
The licensee will issue LER 90-008 to document the details of this event.
Routine followup will be performed by the inspectors during review of the LER.
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On March 16, 1990, the licensee identified a problem for potentially overpressurizing the AFW lines. The licensee identified, during design basis reconstitution efforts, that the water trapped between the normally closed containment isolation valves could heat up and cause the pressure in the AFW lines to exceed its design value. The heating effect on the piping, caused by a main steam line break or a loss-of-coolant accident in containment, could cause the pressure in
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the piping to increase to approximately 3900 psi.
The design pressure of the piping is 1660 psi.
The AFW lines are susceptible to the heating effects due to the long length (approximately 40 feet) of uninsulated piping located inside containment.
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The plant was in a refueling shutdown when this problem was identified; therefore, no immediate safety concern was apparent.
The Division Manager, Nuclear Operations stated that this issue j
would be resolved prior to the end of the refueling outage.
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The licensee will issue LER 90-009 to document the details of this event.
Followup will be performed during review of the LER for closecut.
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On March 28, 1990, the licensee experienced a problem where EDG 1 attempted to start inadvertently.
Licensee personnel were
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performing a valve and switch lineup in preparation for testing EDG 1 after completion of the annual engine overhaul.
EDG 1
attempted to start when the mode selector was placed in " auto."
At the time of this event, the licensee had not completed the lineup of the EDG starting air system; therefore, the starting air tanks only contained approximately 50 psig (normal air pressure is approximately 250 psig).
Due to the low pressure in the air tanks, the EDG air-operated starting motors were rotated, but did not engage with the EDG engine starting gear. Therefore, the EDG did not actually attempt to start.
The EDG was designed to start in standby (idle speed and the EDG output breaker remains open) in the event a low-voltage signal is present on a electrical bus normally supplied by offsite power.
This feature was provided as an anticipatory start in that the loss of voltage on an offsite-supplied bus is an indication of potential electrical distribution system problems.
At the time licensee personnel placed the EDG mode selector switch in " auto," Bus 1Al (an offsite powered bus) was deenergized for preventive maintenance; therefore, EDG 1 attempted to start.
This event did not affect safe operation of the plant as the plant was in the shutdown cooling (SDC) mode of operation and the power to the SDC system was unaffecte _
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Routine followup will be performed on the LER.
k.
On April 2, 1990, with the core off-loaded to the spent fuel pool, a technician performing" Calibration Procedure CP-A/102, " Pressurizer Pressure Channel 102, caused an inadvertent ESF actuation by unblocking Channel A of the PPLS. As per design, this tripped the relays for SIAS, CIAS, VIAS, and the recirculation actuation signal (RAS) tripped because the safety injection and refueling water tank was drained for maintenance.
Due to the physical configuration of the plant at the time, only the containment isolation valves closed and the control room Radiation Monitor RM-065 actuated.
The high and low pressure safety injection pump controls were in override and the containment spray pumps were in service filling the refueling cavity.
The EDGs were in the "off-auto" mode.
The inspector reviewed the applicable schematic and wiring diagrams with the systems engineer and found that the PPLS block, designed to prevent ESF circuitry from receiving a low pressure signal when the
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plant is depressurized, required the 120-Vac power source to remain
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energized.
The technician lifted a wire, causing an open circuit,
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and unblocked the PPLS circuitry.
i The licensee is in the process of upgrading all plant procedures.
Procedure CP-A/102 is one of the licensee's older procedures.
It provided acceptance criteria for the calibration of the pressure channel but essentially left the methodology up to the skill of the craft. The newer procedures are much more prescriptive.
The procedure intended to replace CP-A/102 is Procedure IC-ST-RC-0025, I
" Channel Calibration of Pressurizer Pressure, Loop A/P-102." The l
procedures had been written and had been through the licensee's l
verification and validation process, but had not yet been approved l
by the plant review committee.
Records indicated that the majority
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of the procedure was validated in October 1989, but validation was not completed until March 7, 1990, when it was returned to the procedures upgrade group for comments.
Theprocedurehadundergone a " talk-through" validation as allowed by the licensee's writer s guide, in lieu of the " walk-through" method. Both methods are recognized by NUREG/CR-3968 as acceptable.
In December 1989 the Supervisor, Maintenance directed that all procedures within his area of responsibility be validated via the l
walk-through method. Also, on February 21, 1990, the licensee placed the responsibility for validation of calibration procedures under the direction of one individual in an effort to achieve consistency in reviews.
The guidance given validation personnel in the procedure writer's guide was essentially to " validate the procedure by simulating or performing, to the extent possible, the procedure steps exactly as
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written." During all modes of operation, equipment cannot be" manipulated without adverse actions, thus making the validation
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process difficult.
As a result of this inadvertent ESF actuation, the inspector met with the Supervisor, Instrument and Control (I&C), the lead I&C technician, and representatives from the procedures upgrade project.
It was agreed that the validation process could be enhanced for instances where a complete walk-through was not practical.
The enhancement would be in the form of proceduralized guidance to the validation personnel.
The licensee will issue LER 90-11 to document the details of this event.
Routine followup, including review of the licensee's validation process for procedure upgrades, will be performed during review of the LER.
1.
On March 31, 1990, during planned refueling outage maintenance work on raw water (RW) Valves HCV-28828 and HCV-2883B, the CCW heat exchanger outlet valves used to throttle RW flow, the licensee identified a wall thinning problem with the 12-inch piping immediately downstream of the valves.
The piping was installed per ASME Code B31.7 and had a nominal thickness of 0.375 inches.
In the area where the thinning occurred, the piping had eroded to i
0.100 inches, i
The licensee concluded that the degradation was due to the i
impingement of river sand and silt on the pipe caused by throttling i
of Valves HCV-28828 and HCV-2883B.
Tne affected piping has been in
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service since 1981, when the valve design was changed to facilitate
RW throttling.
The licensee perforned ultrasonic testing, both upstream and downstream of the affected areas, and the results indicated that the erosion was localized and caused by the impingement effect.
Piping surrounding Valves HCV-2880B and HCV-2881B, which perform similar throttling of RW flow, was inspected and no significant erosion was detected.
The licensee initiated an engineering assistance request to study
changing the design in an upcoming outage.
Currently, the licensee has replaced the affected piping with the same valve and piping configuration for the upcoming operating cycle.
Although seriously degraded, the condition did not violate the
minimum wall thickness per hoop stress analysis techniques.
The licensee contended that, at the current erosion rate, the piping j
could have served another cycle prior to violating minimum wall thickness requirements.
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1 Replacement vah es for HCV-2BBOB, HCV-2881B, HCV-2882B, and HCV-2883B were received from a vendor on an expedited basis. Only commercial grade valves were available in a timely manner. As a result QA requirements, in accordance with Appendix B to 10 CFR Part 50, were not invoked during procurement.
The valves were intended for installation via the licensee's
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commercial grade dedication program.
However, the licensee concluded that the valves cannot be dedicated as intended, since source verification was not available.
Since the replacement valves cannot meet the QA requirements of the original specification, the licensee generated SAO 90-07, " Lack of Commercial Grade Dedication for HCV-2880B, HCV-2881B, HCV-2882B, and HCV-2883B." The SAO concluded that the new valves were not outside the design basis even though quality assurance documentation was not available.
The licensee will take compensatory measures to ensure that operability of the components is verified through augmented inservice inspection.
Region IV specialists and NRR have reviewed the SAO.
No problems were noted with the licensee's justification for operability.
It appeared that the licensee was providing adequate response to plant events and issues identified during reconstitution of the design basis.
The appropriate level of management oversight was apparent during review of the issues discussed above.
11.
Installation and Testing of Modifications (37828)
The inspector reviewed the installation and testing of the following:
a.
NUREG CR-0660 listed engine starting failure as the most frequent malfunction for EDGs.
Most malfunctions were attributed to moisture in the EDG starting air system. As a result, the licensee installed desiccant-type air dryers in the starting air lines for each EDG in accordance with MR-FC-86-77, " Dryers for EDG 1 and EDG ? Starting Air."
The inspector reviewed the design package for the modification and determined that the modification did not impact the design basis as defined by the USAR.
Additionally, the inspector reviewed the licensee's safety evaluations for design, construction, and postmodification testing and concurred with the assessment that the system design, irstallation of the design, and subsequent testing of the design did not constitute an unreviewed safety question.
The licensee added non-CQE (i.e., safety related) air dryers between the non-CQE air compressors and the CQE (i.e., nonsafety related)
check valves that maintain pressure in the CQE air start accumulators. The inspector verified that the installation
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conformed to the appropriate codes and standards. The piping and equipment installed by this modification are replacements per
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ASME XI, 1983, Article IWA-7000.
This allowed the use of ANSI B31.1-1986 which exceeded the original design requirements for this portion of the system.
Routinely, during this and previous inspection periods, the inspector observed work in progress toward the installation of the i
four air dryers.
The craftpersons were always found to be working
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with the modification package and approved field installation
drawings. The field installation engineer was frequently observed
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at the worksite overseeing the installation and resolving i
discrepancies between design and field installation.
Although the inspector missed the window of opportunity to observe the testing of the new installations, the certified test records were examined. No significant problems were noted.
Based on the reviews and observations made by the inspector, it appeared that the licensee installed the modification in accordance with the appropriate regulatory requirements. Appropriate oversight
was evident by the presence of the engineer in the field to resolve technical issues, b.
Although not a permanent modification to the reactor plant, the inspector examined the design and operation of the alternate spent fuel pool cooling system that was installed in accordance with SP-ASFPC-1, " Alternate Spent Fuel Pool Cooling System." This system was critical in the licensee's execution of major outage work because it allowed the removal from service of the CCW and RW systems that would normally remove decay heat from the SFP. The licensee instituted this temporary design change under the provisions of 10 CFR Part 50.59.
The inspector reviewed the licensee's analysis and concurred with the assessment that the installation and operation of the system did not constitute an unreviewed safety question.
The inspector also reviewed the system design and operational procedures and noted that they appeared to be adequate.
13, Exit Interview The inspectors met with Mr. W. G. Gates (Division Manager, Nuclear Operations) and other members of the licensee staff on April 20, 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.
During the exit meeting, division management confirmed the commitments identified in the cover letter to this inspection report.
The licensee did not identify any information as proprieta ry.
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