ML17279A734
| ML17279A734 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 12/08/1987 |
| From: | Martin J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17279A733 | List: |
| References | |
| 50-397-87-19, NUDOCS 8712230139 | |
| Download: ML17279A734 (12) | |
Text
APPENDIX A NOTICE OF VIOLATION Washington Public Power Supply System P.
0.
Box 968
- Richland, Washington 99352 Docket No. 50-397 License No.
NPF-21 During an NRC inspection conducted on August 3 through 28, 1987, violations of NRC requirements were identified.
In accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1987), the violations are listed below:
A.
10 CFR 50, Appendix B, Criterion V, and the licensee's Operational guality Assurance Program Description, Section 5, require, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances.
Contrary to the above, at the time of, the inspection, the following procedures for testing of safety related equipment were found to be inappropriate to the ci rcumstances.
PED-S218-E-C640 documented testing completed in December, 1983, of DC motor operated valve circuits to demonstrate that installed 5
conductor wiring was acceptable as a replacement for the 9 conductor wiring specified in plant design documents.
The testing was not appropriate in that it did not include all applicable circuit loads nor did it consider the worst case motor starting currents for the loads that were tested.
2.
Surveillance procedures for motor operated valve thermal overload devices (procedure nos. 7.4.8.4.3.2 through 7.4.8.4.3.4, "NOV Thermal Overload Group 2, 3, and 4") were not appropriate in that:
a)
For Group 2, 3 and 4 thermal overload devices, tested in 1985, the test current prescribed by the procedure was incorrect for the time to trip criteria specified.
b)
A For Group 2 thermal overload devices, tested in 1987, procedure revisions changed 5 thermal overload heater sizes but failed to properly change the corresponding test currents specified by the procedure.
This is a Severity Level IV violation (Supplement I).
B.
Plant technical specifications 3.8.1.1 and 3.8.1.2, "AC Sources-Operating and Shutdown" require a minimum fUel oil supply of 53,000 gallons for division 1 and 2 diesel generators.
Contrary to the above, in response to an NRC identified concern involving the measurement of diesel fuel oil tank capacities, the licensee determined that licensee procedures for determining diesel generator fuel oil levels were in error.
These errors resulted in four instances, since 87i2m30i39'71208 PDR ADQCK 05000397 PDR
July 1986, in which the actual amount of usable fuel oil in a division 1 or 2 fuel oil tank was below the minimum technical specification limit of 53,000 gallons.
The worst case involved an 11 day period in October 1986, during which the actual division 1 storage tank level was only 50,230 gallons.
This is a Severity Level IV violation (Supplement I).
C.
10 CFR 50 Appendix B, Criterion V states, in part, that:
"Activities affecting quality shall be prescribed by documented instructions, procedures or drawings... and shall be accomplished in accordance with these instructions, procedures or drawings".
Section 5.2. 1 of the WNP-2 Operational guality Assurance Program Description Manual, states "Activities that affect safety-related functions of plant items shall be described by and accomplished through implementation of documented procedures, instructions or drawings as appropriate."
1.
Plant Procedures Manual (PPM)
No, 1.4. 1, Revision 2, dated September 6, 1984, entitled "Plant Modifications," Attachment 1, Plant Modification Record (PMR) and Instructions, Block 18 states, in part, that the "Plant Systems Engineer..." will sign and date the PMR "indicating that the installation of the modification is complete."
Contrary to the above, at the time of the inspection:
a.
PMR 02-84-1096-1, written to implement DCP 84-1096-0B, was signed and dated by a Plant System Engineer on June 6, 1985, indicating that installation of structural'hielding for two auxiliary steam isolation valves was completed, when in fact the shielding was never installed.
b.
Maintenance Work Request (MWR-AT-0444), initiated to change position indicator light labels to indicate that valves SW-PCV-38A and B were deactivated, was identified as having been completed on the
- PMR, as specified by a Plant System Engineer's signature on May 28, 1987, although the work had not been done.
This is a Severity Level IV violation (Supplement I).
2.
Automatic Depressurization System design drawing FSK-346, Revision 3, dated June 18, 1983, requires that "shims be placed under (nitrogen) bottles as required depending on the individual bottle height to achieve a snug fit between the top of the bottle and the collar of the rack."
Contrary to the above, as of August 3,
- 1987, shims had not been installed for any of the ADS nitrogen bottles, with the result that the bottles were free to move in the collars during a seismic event.
This is a Severity Level V violation (Supplement I).
Procedure No. 10.25.46, "PGCC Modification and Cable Installation",.
provides installation requirements for permanent electrical terminations.
The procedure provides specific requirements for installation of terminal lugs and heat shrink tubing, such that terminals are properly crimped and bare conductor wire is not exposed.
Contrary to the above, as of August 3, 1987, automatic depressurization system instrument rack termination crimping, terminal lugs and heat shrinking were not installed in accordance with procedure
- 10. 25.46 in Instrumentation Racks No. IR-67, IR-68, IR-69 and also in the Control Room Cabinet H-13 P631 ADS DIV. 2.
In particular, terminations were improperly crimped and heat shrink tubing was improperly installed such that bare wire was exposed.
This is a Severity Level V violation (Supplement I).
Licensee procedure 1.3.7, "Maintenance Work Request",
provides requirements for performing work on safety related equipment.
The procedure requires that all work be performed in accordance with a written work request and that any modifications to safety related equipment be properly reviewed in accordance with applicable requirements of 10 CFR 50.59
'ontrary to the above, as of August 3, 1987, the licensee was observed to have installed temporary foam insulation filters on the ventilation louvers for the 4KV breakers on safety related SM7 switchgear without the use of a written work request and without proper review of the modification.
This is a Severity Level V violation (Supplement I).
Licensee procedures 10.2.53, "Seismic Control for Scaffolding,
- Ladders, Tool Gang Boxes and Metal Storage Cabinets" and 1.3. 19 "Housekeeping",
provide specific requirements for ensuring the proper seismic restraint of equipment in safety related areas and for proper cleanup of work areas following maintenance activities.
Contr ary to the above, at the time of the inspection:
An unsecured tool box, breaker handling truck, ladder and several sets of disassembled metal brackets and mounting hardware were observed adjacent to safety related switchgear in ESF switchgear room SM7.
b.
An inspection of containment electrical penetration enclosure X-105A (TB-R312) for Division 1 electrical circuits identified several loose terminal block screws, bare wire remnants, scrap tape and other debris inside of the enclosure.
This is a Severity Level V violation (Supplement I).
Plant Problem Procedure 1.3. 12, "Plant Problems",
Revision 10, Sections 1.2. 12.5 and 1.3. 12.5, provide specific requirements for
the preparation and issuance of non-conformance reports (NCRs) when plant equipment deficiencies are observed.
Specifically, the procedure requires the issue of an NCR in the event of failure of plant equipment and requires that the NCR properly indicate whether the equipment is "safety related" and whether the problem is "safety significant".
Contrary to the above:
in June
- 1987, NCR 287-219 was issued withoUt proper indication of the safety significance of a failure of safety related valves CIA-V-39A and CIA-V-39B; and in July 1987, when the same valves again failed, no NCR was issued.
This is a Severity Level V violation (Supplement I).
D.
Plant technical specification 6.8.3 states that "Temporary changes to procedures of specification 6.8. 1 may be made provided... the change is approved by two members of the unit management staff, at least one of whom holds a Senior Reactor Operator license; (and) the change is documented, reviewed by the POC and approved by the Plant Manager within 14 days of implementation."
Station procedure 1.2.3, "Use of Plant Procedures" implements the above requirements for making procedure changes.
Contrary to the above, on May 15, 1985 and May 7, 1987, maintenance personnel-performing procedure 7.4.8.4.3.4 and 7.4.8.4.3.2, "MOV Thermal Overload Group 4" did not make a temporary procedure change in accordance with Procedure 1.2.3 when they noted that installed thermal overload devices did not match the size specified in the procedure.
- Instead, the maintenance personnel noted the different thermal overload devices and revised test currents in the comments section of the procedure.
In two
- cases, RCC-V-6 and RHR-V-3A, the revised test currents were inco'rrect and did not correspond to the required device trip time criteria.
This is a Severity Level IV violation (Supplement I).
Section 6.8.1.a of the Technical Specifications requires applicable procedures recommended in Appendix 'A'f Regulatory Guide 1.33,
- February, 1978, be established and implemented.
Section B.a of Appendix
'A'f Regulatory Guide 1.33 requires that, "Procedures of a type appropriate to the circumstances should be provided to ensure that tools,
- gauges, instruments,
- controls, and other measuring and testing devices are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy.
Specific examples of such equipment to be calibrated and tested are readout instruments, interlock permissive and prohibit circuits, alarm devices,
- sensors, signal conditioners,
- controls, protective circuits, and laboratory equipment."
Contrary to the above requirements, as of August 3, 1987, procedures had not been established for the periodic calibration of time delay relays associated with permissive and protective functions of the following safety related time delay relays:
(1)
SE-RLY-V/2A3 and 2A4, that. provide 12 second and 62 second time delay values to control the slow opening of the service water pump discharge valve to minimize water hammer effects.
(2)
SGT-RLY-TK/2A1 and 2A2, that provide a 30 second time delay for automatic start of the redundant standby gas treatment system.
(3)
RHR-RLY-K54A, that provides a 10 second time delay for minimum flow bypass for the RHR pump.
(4)
RHR-RLY-K70A, that provides a
5 second time delay for starting of the RHR pump.
(5)
RHR-RLY-K93A, that provides a 10 minute time delay before the operator can manipulate RHR heat exchanger valves after the start of an accident.
This is a Severity Level'V violation (Supplement I)
Pursuant to the provisions of 10 CFR 2.201, Washington Public Power Supply System is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555 with a copy to the Regional Administrator, Region V, and a copy to the NRC Resident Inspector, within 30 days of the date of the letter transmitting this Notice.
This reply should be clearly mar ked as a'Reply to a Notice of Violation" and should include for each violation:
(1) the reason for the violation if admitted, (2) the corrective steps that have been taken and the results
- achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken.
Consideration may be given to extending the response time for good cause shown.
FOR E NUCLEAR REGULATORY COMMISSION Dated Walnut Creek, California this day of December, 1987 J.
B. Martin Regional Administrator
APPENDIX B Summar of Si nificant Findin s
Inade uate Control of Plant Desi n
Re uirements V
Station Batteries and DC Electrical S stem (1)
Battery Design Errors The team reviewed the design basis for station safety related
'atteries and noted several problems involving a lack of understanding of the design basis and failure to control proper implementation of specific requirements.
Although the team concluded that the errors did not result in inoperability of any battery, the errors significantly reduced available margin for battery performance under accident conditions.
For example:
(a)
Battery calculations for the 250VDC and 125VDC Division 1 and Division 2 batteries did not include correction factors to account for battery operating conditions permitted by the plant technical specifications.
In particular, the calculations did not include correction factors for battery aging, temperature or specific gravity variations.
(b)
Battery calculations were not properly updated to account for revised battery characteristics following replacement of 250VDC batteries in 1983.
(c) 125VDC Division 1 battery calculations were not properly updated to account for as-built wire runs between motor operated valves and their motor control centers.
The battery voltage drop calculations were based on load center wiring having a larger conductor size than that actually installed in the plant.
Furthermore, design calculations appeared to address an arbitrary allowable voltage drop between the motor control center and supplied loads.
The calculations did not appear to address the overall question of the total expected voltage drop between the battery and the loads, considering degraded battery voltage, starting current requirements or minimum allowable equipment voltages.
It also appeared that some class lE loads were not included in the calculations.
(d)
Although calculations were updated following the 1983 replacement of 125VDC batteries, the updated calculations were incorrect in that they did not properly consider the most limiting case loading during the first minute of the transient.
(e)
The design calculations for the 250VDC and 125VDC Division 3 batteries did not properly account for DC motor in-rush current.
The calculations were based on initial starting currents that are significantly less than those actually experienced.
(2)
Battery Surveillance Inadequacies The team reviewed the surveillance procedures implemented by the licensee for ensuring that station safety related batteries retain their required design char acteristics during plant operation.
In this regard, the team noted several problems with the procedures for performing the 18 month service test on the 125VDC and 250VDC batteries.
In particular:
(a)
No temperature compensation was used to adjust the test load current for test performance above the 60F design rating of the battery.
(b)
The load profile specified for testing the 125VDC batteries used lower currents following the first 3 seconds of the transient than those specified in the FSAR and battery design calculations.
(3)
Post Modification Testing Inadequacies The team noted that the licensee performed a design verification test on plant MOVs in lieu of performance of a design modification to increase the number of conductors in the wire runs between the motor control center and the valves.
This test appea~ed to be inadequate in that the test considered only motor running current and not the higher starting current.
Diesel Generators and AC Electrical S stem (1)
Common Mode Failure of Diesel Generator Fuel Systems The team noted that the licensee had not performed a proof test of the floor drains in the diesel generator (DG) rooms.
Furthermore, the team noted, that activation of the fire protection system in the Division 3 diesel generator (DG) room could supply enough water to potentially overload the room floor drains.
Preliminary licensee calculations indicated that water in the room could reach a depth of greater than 8 inches in about 17 minutes.
Therefore, after about 17 minutes, water would overflow into the adjacent Division 1 and Division 2 fuel oil pump pits, failing these pumps.
With the main fuel oil pumps inoperable, both trains of DGs would become inoperable in about 5 or 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (based on the low level alarm point for the DG day tanks).
(2)
Common Node Failure of Diesel Generator Air Intake Systems
The team reviewed the design basis for the DG air intake system and the design change packages associated with recent modifications to the air intake system.
The team noted several concerns with the design change which implemented a volcanic ash filtration system.
Specifically:
(a)
The system design calculations did not support the design basis or filter changeout requirements.
In particular, the team noted that the new filters would exceed their loading capacity in approximately 19 minutes, which is not consistent with filter changeout capabilities.
(b)
The new filters appeared to be installed backwards, in that differential. pressure due to filter loading would tend to unseat rather than more firmly seat the filters.
(c)
The licensee had not performed a proof test of the new design or performed a walkthrough of system emergency procedures.
(3)
Inservice Testing Deficiency The team reviewed the licensee inservice testing program associated with the diesel generators.
In particular, the team noted that the licensee was not properly testing check valves in the fuel oil supply to the diesel generator.
The diesel fuel oil supply system includes check valves in parallel which are not being individually tested to assure proper operation.
(4)
Improperly Controlled Plant Modification The team noted that the licensee had installed temporary foam insulation filters on the ventilation louvers for the 4KV breakers on safety related SM7 switchgear.
These filters were not installed using a maintenance
- order, as required by station procedures, nor was the modification properly reviewed as required by 10CFR50.59.
Standb Service Water S stem (1)
Time Delay Relay Design and Testing Problems The team reviewed licensee design and testing requirements for safety related time delay relays in the standby service water system.
The team noted that the licensee had not documented the design basis for these relays or similar relays in other safety related
- systems, nor were the relays being periodically tested as required.
(2)
Motor Operated Valve Thermal Overload Test Problems The team noted several instances of test deficiencies associated with motor thermal overloads.
In particular, the team noted some instances in which the conducted test did not
(3) properly confirm the specified design margin on motor tripping (e.g.
the motor may trip too soon under high load operation).
The team also noted instances in which the test results appeared to indicate improper overload operation, for which no corrective actions were initiated (e. g. applied test currents should have tripped the overload and did not).
Incomplete Implementation of Design Change The team reviewed several design change packages to determine if all aspects of required packages had been properly completed.
The team noted a minor design change implementation problem associated with failure to properly modify control room service water system indicators to properly reflect a modification to plant hardware.
However, the team noted a much more significant design change implementation problem associated with another safety related system.
In particular, the team noted that plant design modification (DCP 84-1096-OA and OB) was'erformed in September 1984.
This modification installed new safety related auxiliary steam isolation valves (DCP OA) and missile shielding for these valves (DCP OB).
Each of the design packages (OA and OB) required that both DCPs be completed in order to consider either DCP to be complete.
Both DCP packages were signed off as complete and station drawings were revised in July 1985 to show the additional valves and shielding.
However, the required shielding was not installed.
(3)
Improper Spray Pond Temperature Monitoring The team reviewed the design of instrumentation for monitoring the temperature of water in the spray ponds.
Plant technical specifications require that pond average temperature be maintained below 77F.
The team noted that the location of the temperature sensors used to meet this requirement appeared to be improper in that the sensors are located near the bottom of the pool, under the pump house.
The team did not consider that this location properly provided a representative average temperature of spray pond water.
Automatic De ressurization S stem Weak Implementation of a Design Change to Install an ADS Inhibit Function The team reviewed design changes associated with the automatic depressurization system (ADS).
Plant design modification (DCP 85-0073-OA) modified the ADS actuation permissive cir'cuitry to remove drywell pressure as an input and added inhibit switches to prevent inadvertent ADS actuation in the event of an ATWS.
The inhibit switches were installed by the licensee as part of the fulfillment of a TMI action item.
NRC approval of the TMI action item was based on use of inhibit switches only for ATWS
- events, not for other design basis events described in the FSAR.
Emergency operating procedures issued by the licensee
for use of the inhibit switches do not place any constraints on the use of the switches.
This is a significant concern, since improper use of the inhibit switches reduces the availability and reliability of ADS in performing its required safety functions.
The team also noted that INPO raised a similar concern in late 1986, and the licensee had not yet implemented corrective action.
(2)
Improper Sizing of Backup Nitrogen System The team noted that the backup nitrogen system for ADS did not appear to meet the design requirements specified in the FSAR.
Specifically:
(a)
The FSAR specifies that the system support 30 day operation involving 48 valve cycles,
- whereas, the design calculations address 30 day operation with only 18 valve cycles.
(b)
The design calculations use a smaller valve cycle nitrogen volume than assumed in the FSAR.
(3)
Improperly Installed Backup Nitrogen System The team noted that the gas cylinders for the backup nitrogen system for the ADS valves were not installed in accordance with plant design requirements.
The system design provides for the'ottles to be securely clamped in their respective seismic restraints.
The installed configuration did not securely clamp the cylinders and allowed significant movement.
2.
Plant Material Condition and Housekee in Deficiencies Inade uate Seismic Restraint of E ui ment The team noted that the licensee was not providing adequate attention to the seismic restraint of equipment in safety related areas to prevent seismically induced interaction of material with safety related components.
This concern had been raised in previous NRC inspection reports.
In particular:
Seismic restraints were observed to be improperly restored on backup N2 cylinders for ADS following nitrogen cylinder replacement.
The licensee had no procedure addressing requirements for proper cylinder replacement.
(2)
The overhead crane in service water pump house lA was observed to have it's block extended such that it could impact safety related conduit during a seismic event.
The licensee had no procedure covering control and stowage of lifting equipment installed in safety related areas.
This is a repeat of a similar concern raised in a previous WNP-2 inspection report (86-33-01).
(3)
During the first week of onsite inspection, an unsecured tool box and breaker truck were observed in the safety related SM7 switchgear room.
These are heavy and relatively easily moved items which could damage important safety equipment during a
seismic event.
It appeared to the team that these items should be stored elsewhere or properly secured.
During the second week of onsite inspection, the team noted that the breaker truck and tool box had been removed;
- however, the team again noted that ladders were left stored in both the SM7 and SMB switchgear rooms and several sets of disassembled metal brackets and mounting hardware were piled in the corner of the SM7 switchgear room.
(4)
Temporary scaffolding was observed to be installed in the vicinity of the backup N2 system for ADS since June 1987.
b.
Inade uate Housekee in The team noted that the licensee was not providing adequate attention to plant housekeeping.
The following deficiencies were observed:
(1)
Piles of disposable absorbant towels and several cardboard boxes were observed in the DG rooms.
This debris would contribute to drain plugging in the event of fire system actuation.
(2)
A pile of drawings and papers, a discarded candy wrapper and several pieces of loose wire were observed on top of breaker cubicles in the SMB switchgear room.
(3)
Numerous cigarette butts and a cigarette wrapper were observed within the no smoking area adjacent to the diesel generator fuel oil tank fill manifold.
Inade uate Plant Material Condition k
The team noted that the licensee was not providing adequate attention to plant material condition.
The following examples were noted:
(1)
An inspection of containment electrical penetration enclosure X-105A (TB-R312) for Division 1 electrical circuits identified several deficiencies including numerous loose terminal block
- screws, bare wire remnants, scrap tape and other debris inside of the enclosure.
Also, several broken insulation spacers were noted on terminal blocks within the enclosure.
(2)
A walkdown of the instrumentation panels associated with the ADS backup nitrogen system identified several electrical termination deficiencies that were not in accordance with the requirements of licensee maintenance procedures.
Examples included improperly crimped terminations and improperly-installed heat shrink tubing, such that bare wire was exposed.
(3)
The team noted that an electrical conduit to the MOV on the discharge of a standby service water pump was broken and supported by the enclosed wiring.
This deficiency had not been observed or corrected by the licensee.
Failure of this valve to open would make one train of the standby service water system inoperable.
(4)
An inspection cover was not installed on the side of breaker 86/8-3 in the SM8 switchgear room.
3.
Inade uate Root Cause Assessment and Corrective Action The team noted instances in which the licensee did not appear to have adequately conducted root cause evaluations associated with equipment malfunctions.
A significant contributing cause appears to be the lack of an effective equipment history trending program.
For example:
(a)
The team noted several NCRs associated with failures of automatic valves for isolation of non-safety related air to the ADS control system.
The system failed to operate properly in July 1986.
During a June 1987 surveillance, both trains of automatic isolation valves failed to function.
In addition to improperly classifying the NCR as non-safety related, the NCR process failed to address prior fai lure of the valve or identify the same failure mechanism.
It was not until the third failure in July 1987, that the licensee performed an adequate root cause evaluation and took corrective action to modify the closing force on the valve.
(b)
The team noted that several NCRs have been issued and closed involving repeated failure of control valves associated with the diesel generator fuel oil day tanks.
The NCR dispositions failed to address prior failures or indicate any effective corrective action to preclude recurrence.